Earnings Transcript for TLW.L - Q4 Fiscal Year 2017

Executives: Paul McDade - CEO & Executive Director Les Wood - CFO & Executive Director

Analysts: Brendan Warn - BMO Capital Markets Amy Wong - UBS Investment Bank Michael Alsford - Citigroup Sasikanth Chilukuru - Morgan Stanley Mark Wilson - Jefferies LLC David Mirzai - Deutsche Bank AG Al Stanton - RBC Capital Markets Rafal Gutaj - Bank of America Merrill Lynch Alwyn Thomas - Exane BNP Paribas James Thompson - JPMorgan Chase & Co. Colin Smith - Panmure Gordon & Co. Job Langbroek - Davy

Paul McDade: Good morning, everyone. I think we'll get started. Thanks for coming along to our 2017 full year results. I think, actually, I was just thinking, the last time we were here was the interims, which - but it was a kind of first set of results for the new exec team. I think we were talking about our first 90 days. It seems like a lot longer than 90 days now. But I think we can say that the new team is well embedded and confidently and successfully managing the business, and hopefully we will show that today. This slide I showed at the last results, and I think what we were seeing at that point was that in the short term medium term, our primary focus had been on kind of commitment to disciplined cost management, maximizing revenue and balancing the use of cash carefully between strengthening the balance sheet and investing in the assets, and then a continued optimization of the portfolio. In the medium term, we were committed to looking for ways to grow the company and deliver shareholder returns. And I think from the presentation today, and hopefully the results statement this morning, you will see that we're very much on track in delivering what we said we would do. In terms of just a high level overview of delivering on those objectives, in terms of the short to medium term, we significantly improved the financial foundation of the business. Free cash flow almost $550 million, exceeded, I think, everyone's expectations. And the deleveraging of the business down to 2.66x, almost on a kind of policy level of 2.5x. So really hard work and a lot of detailed focus has kind of reset the foundation of the business, and Les will talk a bit about that more. We've continued to high-grade the portfolio through both asset sales, obviously, the big one being Uganda last year, which we'll complete this year. But also there's quite a lot of small deals have been going on in the background around exploration, farm-downs or kind of Norway, Netherlands, gas sales. And then across the main assets in West and East Africa, I think the big message there is as we went into '18 and we're now going to - sorry, into '17, we're now going to '18, we've done a significant de-risking of those assets through 2017. If you look in West Africa, we had debt losses ahead of us, that loss is now behind us and came out very much in our favor. TEN, we had the challenge of the wells at the beginning of last year. Those have exceeded expectation. We exited the year at 70,000 barrels a day, kind of removing any doubts over that field. Jubilee field was approved by the government. So we're free to now get on and invest there. The TR Project, we're kind of goal [indiscernible] no definition and we're doing a very good execution at the moment. And then over in East Africa, obviously, I talked a bit about the Uganda deal, which is very important. But also, as we'll talk today, Kenya, the appraisal program, is behind us and we're now firmly focused on moving to cash flow through a development of the Kenyan assets. And then in the new ventures front, Angus and Ian and the team are working very hard resetting the portfolio in '15 and '16, '17 was a record year for seismic acquisition for us, and really all about positioning ourself for restarting high-impact exploration. Again, we'll hear a little bit more about that today. So I think in '17, exceptional year of delivery and, more importantly, we've maintained our focus on what we said we'd do we did. So maybe with that, I'll hand over to Les to talk a bit some more of the details, and then I'll come back and go through some of the operational update and wrap up.

Les Wood: Thanks, Paul. Morning, everyone. It gives me great pleasure actually to be stood here this morning talking about the good set of results that we announced earlier this morning. So clearly, as you can see from the picture here, we made really good progress in 2017. This slide demonstrates the huge amount of hard work that's we've paid - that's actually paid off on the basis of what we've done as a team. And obviously, it reflects the much-appreciated support and assistance of our shareholders earlier in 2017. We've only got green arrows on the picture, and I hope that I'll be able to be able describe that level of progress as we go over through the course of 2018. Of particular note, and what I would emphasize and as was mentioned by Paul, is the significant level of free cash flow driven by strong performance right across the business, including our insurance proceeds and, laterally, of course, some firming of the oil price towards the back end of 2017. We do feel that there's further to go on costs. We've made a dramatic improvement on costs, you can see that by the number. Some of that through our own hard work and also adjustments to the portfolio. It's also worth saying, while not on the chart, albeit small, we made the first operating profit as an organization since 2013. And again, much as a result of the sort of the hard work across the organization. And we did have a small loss, but that's really been driven by noncash impairments, which is really a response to the backwardation of the forward oil curve, which just meant we had to take some impairments on our assets, but much lower than we have in the past and really a reflection now that we've got a balance sheet appropriately positioned for the current oil price environment. And the net debt number is down 27% from 2016, still a high number of $3.5 billion, which is absolutely going to be a key focus for us in 2018. And in combination with our adjusted EBITDA, it gives us a gearing of 2.6x, so very close to our policy. The other thing to mention, which Paul alluded to, we've had a huge amount of significant de-risking across the company with some of the events that Paul described, but also, in terms of the balance sheet. So we've significantly de-risked the balance sheet. That was underscored by recent upgrades in our ratings from Moody's and S&P. A reflection I think of what we're doing internally. So all in all, I would say, a good set of results. And so what does it mean now that we're approaching - or what does it signify that we're approaching our policy target? I think very simply, and it's what we've said when we were back at the rights issue, that it gives us to the operational and financial flexibility that we were looking for. It doesn't mean, as I said earlier, that we're going to stop focusing on debt. I mean, quite the contrary, I mean, that still remains a key priority. But it does allow us to fully consider all the uses of cash that are available to us. And as shown here, there are alternatives for the business that are not solely predicated on reducing debt. But what you should be assured of is we'll maintain the same rigor and discipline that we have on the rest of the business as we think on the uses of our alternatives on cash. One of the best examples for that is a potential second rig in Ghana, which presuming and once we've done all the work, it delivers, as we would expect, value. That's something that we have in our - on our own support, it's something that we could actually choose to do later in the year. Given now that we have the financial strength to be able to trigger that option. I was just going to turn a little bit to hedging. It's been quite interesting actually as we've had - hedging has been a really important part of our financial risk management. And the many ways that we approach that, we've been very prudent. That also covers our approach to insurance and also our approach to liquidity management. We're very proud of the fact that over the course of the last two years, we've delivered about $850 million of revenue that would otherwise have not come had we not had hedging. And it's been absolutely critical funds to the running of the business when we were getting prepared to start up TEN and also when we had all the uncertainty with the depressed oil price. And as you can see, as we've stated on the slide here, we're going to continue to systematically do our hedging, it's paid dividends over the last 10 years. And as shown in the diagram, which we have had quite a few questions, people, when we had the floor, were always happy to see that we have the floor. Now that prices have been rising, they were curious to understand, well, what was our exposure to the upside. So this was our endeavor to show the exposure to the upside. And as it shows on the slide, we've got 60% of our production's hedged at $52, which I think is a good place to be. But we've also got significant exposure to the upside above $75. And in the case of the unhedged, fully exposed to the upside. While it's not on this slide, it's also worth noting that we received $162 million in business interruption insurance over the course of 2017. We refinanced our RCF. And right at the end of 2017, we also refinanced RBL. Again, all part of our liquidity and risk management. I was just going to touch a little bit on costs, it's really important to us that having stabilized the business and actually got the business now performing, we would like to grow the business as the sector recovers. We're determined to make sure that the financial discipline that we've worked so hard that's across the business is retained. We'll continue to drive down our operating costs and our G&A. As you can see on this diagram, the latter has been reduced by 50% since 2013, a significant result and there's still room for further efficiency. We also believe there's no reason why we can't be more efficient following the exit of various production barrels from our portfolio. And we still believe there's operational - sorry, operational efficiency to be gained from operating our 2 FPSOs in Ghana, where we've commissioned an operational business excellence project this year. With the cost savings we initiated in 2015, we've saved around $580 million so far by the end of the year, and we're confident that we're going to get to and potentially exceed the $650 million target that we reset for $500 million earlier last year. I think most oil companies would claim at this moment they've reset and addressed their cost base. I certainly believe that to be the case. In Tullow, we've truly embedded a new cost culture and one that we'll endure. Now to just quickly cover CapEx. The discipline, I've talked about, is further demonstrated through our capital expenditure program. It does remain flexible within our range to adjust as oil prices rise and potentially fall. And in 2018, we will spend about $460 million versus $225 million in 2017, which, of course, excludes Uganda, which we've laid out here. But as you can see, we are focusing our capital absolutely on where we are going to get the best returns, in this case in Ghana. So we'll spend about $250 million as we seek to both draw and sustain production after three years of no drilling. In Central West Africa, we're going to have a modest increase. We would happily spend a little bit more if market conditions and the work program put forward by our operators allowed, given again, like Ghana, the high returns that we would expect from that part of the portfolio. In East Africa, we continue to spend carefully as we prepare to take Kenya towards FID and seek to minimize our pre-FID costs. In exploration, we'll spend roughly similar levels as we have in 2017. But on current projections, this number will increase, but not dramatically as - and Paul with talk about it a little bit later, as we look to do more high-end impact drilling in 2019 and 2020. The key, though, is flexibility and discipline. We're able, as we showed in 2017, to be able to match our CapEx to the prevailing market conditions. And I think the range we've set out on the diagram here is still appropriate, and we will be able to respond to market conditions. So it's also worth - maybe the last thing to say on this slide, a reminder that completion of the Uganda deal will also recover the CapEx that we spend in 2017, which is about $60 million. The CapEx to the point that we'll have spent in 2018, $100 million from the completion bonus; with FID in 2018, a further $50 million. So substantial amount to come from completion of the Uganda deal this year. A little bit on production, we delivered strong production in 2017, actually at the highest level that we've produced in the company. Ahead of our expectations and just above the revised guidance that we gave earlier in 2017. TEN, in particular, has benefited from some excellent work by our teams. So you might remember the beginning of the year, we were just feeling our way a little bit. But over the course of the year, the team had to done a fantastic job and have been able to optimize the field's performance, so much so that over the last few months, we've been producing consistently above 70,000 barrels a day. And we're currently producing at 70,000. At a time when oil prices has been hitting $70 a barrel, this has been very welcome indeed. And we set our 2018 guidance to reflect the fact that there are some uncertainty, not least because we haven't drilled in Ghana, like I said, for three years. However, with good delivery and strong operational performance, we could potentially outperform our 86,000 barrels a day. I think you understand, though, that until we see how these initial wells produce and what decline there might be from both fields, we also have the shutdowns ongoing in Ghana, albeit in - sorry, in Jubilee, albeit covered by BI insurance, particularly until the new wells then come online. Any turret-related production losses will continue as they have in 2017 to be covered by our business interruption insurance. So just the last bit for me to wrap before I hand over to Paul. While the market has stabilized and improved somewhat recently, we will not be changing our approach dramatically. We have significantly de-risked the business over the course of 2017 and eliminated, in a number of cases, some key uncertainties, debt loss being a good example. Financial discipline remains key as we seek to maximize free cash flow to drive down debt further. That remains a key priority. We'll invest in our assets in the current portfolios we're doing in Ghana to grow production. But as our gearing drops below our policy level, and like I said earlier we're very close to that currently, it leaves us with much more flexibility to be able to invest and grow the business as the market allows. So with that, I'll hand back to Paul.

Paul McDade: Thanks, Les. Okay. So really, what I want to is just give a little bit of a kind of overview of the asset base and the progress we've been made and then just before wrapping up. I think looking across the board, there's - as I said earlier, significantly de-risked the business and made progress against the targets we set ourselves. In West Africa, ITLOS has been removed and very favorable outcome was a key result last year. And really has allowed this noted progress on and focus on restarting drilling in TEN. The wells that we had in - if you recall, a year ago, we started the year with a forecast of 50,000 barrels a day, which we beat last year. But more importantly, we exited the year in TEN around about 70,000 barrels a day. So although we won't be able to - as we start drilling this month, the first wells will come onstream a bit in the middle of the year. We're feeling pretty good about the TEN assets at the moment, and I'll talk a little bit more about that. In Jubilee, we received the approval in Greater Jubilee project. The TRP - we got a couple of shutdowns we flagged there to close out the TRP project, one of them is underway right now and progressing well. And then as - I think highlighting what Les mentioned, I think the cost performance across the group was good. I think the cost performance in Ghana was exceptional. We set ourself a target back in '15 to get to $8 a barrel in 2018. We were below $8 a barrel in 2017, and I think there's more to come, as Les alluded to, so great cost performance. East Africa and Uganda, we're on track to close the deal and the project itself is on track and overall, as Les mentioned, those numbers getting that deal closed is quite important in 2018, but probably more important as getting the project FID didn't getting access to that circa 23,000, 25,000 barrels a day with no capital exposure up to first oil and beyond. So that's very much on track. Kenya, I'm going to talk about in a moment in terms of the outcomes of our appraisal program and plans for development, significant progress there. And then on the new ventures front, I'll talk a little bit more on than that in detail. But really, we've completed a massive reset of the portfolio and added some really significant new areas in Côte d'Ivoire and Peru. And as I said earlier, massive year for seismic last year. So let me kind of dig in just a few of those areas. In Ghana, the rig is in place at the moment. It will spud later this month. It's on track and it will start off drilling in the TEN field. The way we'll drill, we will drill three wells and then start completing the wells, which means you'll get the first well onstream around about mid-year. And we've - as Les said, it's uncertain in these wells, exactly what they'll contribute initially is a bit uncertain. The kind of well stock has been holding up incredibly well. But we're thinking we might see some decline in that as we go towards the mid-year and the new wells coming on. So maybe we've been a little bit cautious just about the production for TEN, I think appropriately so, but we're feeling pretty good about TEN as we build up. And we shouldn't forget we've tested the TEN FPSO up to levels of 90,000 and 100,000 barrels a day, although the design was 80,000 barrels a day. So if we can get the well stock up and sustain that, that would be a really good boost to production as we move into 2019. I think the cost environment still is where it's been for the last year or so. We are seeing no inflation whatsoever on services of rigs, almost kind of the opposite. We're bounced in and around the bottom. These wells drilled and completed, they're about 40% less than what they were at peak. That's a significant reduction. And we expect it to stay that way for the - certainly 2018. And a little bit beyond that, we don't see any uptake on costs. And as Les alluded to, we are looking at whether to put in a second rig. The balance there is we've now got an efficient plan for the first rig. We're looking at the delta a second rig can bring. Bringing in just - maybe add three, four wells drilled and completed - sorry, drill, leave the other rig to complete them and get out. And that's something we're just sort of looking at how does the capital allocation look? Is it efficient? Does it add value? It certainly would impact to 2019 production, and that analysis is ongoing. And of course, the kind of bigger overlay is we've been able to pick up these rigs at incredible low cost. So this is a good time to be investing. So that's a judgment we'll make, but we're as equally focused on free cash flow for 2018 as we are on capital investment. And so really, I think the kind of summary is with Ghana is both on TEN and on Jubilee. We put the pie charts back in at the bottom just to show the massive resource base we have across those two fields. And this doesn't even start to consider some of the kind of near-field exploration opportunities we see in and around Jubilee and TEN. And as you would have seen in the statement, we've picked up another license over the border in Côte d'Ivoire, CI 524, which is adjacent to the TEN license. And we see that as in - I mean, we hope we find something very big there, and it can be a stand-alone development within Côte d'Ivoire. But even if it's a marginal discovery, there's an ability to tie that back into the existing infrastructure within Ghana. So great synergies there. So exciting to get going again in Ghana and really starting to build momentum in terms of production and revenue. Kenya, as we look at Kenya, important day today in terms of what we're seeing. We finished all the assessment of the significant appraisal program, 21 appraisal wells drilled. A lot of testing done, both reduction and injection testing. And as you know, we're moving on to the early oil, which will give us even more data as we get through 2018. Our conclusion from all that work is that we're pleased with the 560 million 2C number, so that's - we've discovered resources of 560 million barrels with a huge upside potential. 670 million barrels of upside potential beyond that 560 million. So this very much underpins our previous view of the prospectivity of the basin for those that want to kind of try and compare the guidance that we've been giving through the exploration phase of 750 million. It was a Pmean number. Obviously, it was a number we gave when there was a great deal of uncertainty. And generally, for those of you who want to do the math, Pmean generally sits somewhere between 2C and 3C. So great, great outcome for the resource base, massive amount of oil in place, up to 4 billion barrels in the basin. And we just feel this completely underpins the development, which I'll now go on and talk about. And just at the bottom, we haven't finished, there is exploration upside in and around the basin as well. But our focus now is very much on development. The overall development plan, as you're aware, is an export pipeline to Lamu. We proposed to the government - the drivers here, the government are very keen to move forward with this development. They're very keen to get to FID. Why? Because they want to get first oil and they want to move this project forward. So that was one consideration. Another one is really around the low-cost environment we're in. The sooner we can get this project to FID in like contracts, over the border in Uganda, we're starting to see some of the pricing and we're starting to see the cost base there. Because we will lock in these low costs in Uganda because we will FID that project this year. And we're taking those lessons across to Kenya and realizing that the quicker we can get this underway, the more likelihood we'll lock in a very low-cost CapEx for the project. And then the other thing I believe is that momentum is what these projects are all about. You've got to build momentum, drive momentum and move them forward. You saw us do it hugely successfully back in 2008 in Ghana where we just - in the earlier approved, we moved Jubilee forward and we got it onstream in 40 months. We want to build the same momentum here and get this project underway. So we're going for a phased approach. Ultimately, the project will reach 100,000 barrels a day plus. But the foundation stage that we're moving forward with, we've kind of selected a core part of those 560 million barrels in Amosing and Ngamia, the best-assessed fields that we have. Those fields and the core areas in them can deliver 60,000 to 80,000 barrels a day, and we will get that project underway. And you can see the timeline, it's pretty aggressive. FID in '19 and first oil maybe in '21, maybe more likely in '22. But we're going to set ourselves some tough targets and try and meet them. And then when you look at the overall capital spend, the team, Mark and his team, have been driving down the capital costs both on the basis of the kind of external market and based on some of the efficiencies and redesigns and what we've been doing in Uganda. This is almost a replica project for the one that is next door in Uganda. So there was a lot of lessons and information we can carry across and apply here. So really excited today to be kind of announcing this and moving it forward. We're working now that the election period, extended as it was, is over. We're really back heavily engaged with the new government in Nairobi, and the local government up in Turkana, and we'll obviously progress on this project in 2018. On the exploration front, for a company like Tullow who's been probably quiet over the last couple of years, it's not been quiet. In-house, there's been a heck of a lot of work going on. Really, we've always seen exploration as a key part of our long-term growth strategy. And bear that in mind, over '15 and '16, what we were doing was working to reset the portfolio. That meant scrutinizing the portfolio, removing what we think wouldn't work in the new environment we're in today in the industry and really hanging on to and rightsizing in terms of equity levels the places we wanted to stay. A huge amount of work have been done around the kind of portfolio management of the - what was the existing portfolio. And then you've seen us, we've been doing a lot of new ventures work, big new positioning in Côte d'Ivoire, okayed the 524 license, it's really an adjunct to our kind of tangibly position. More here, I'm talking about the large tranche of acreage, which we announced yet another license today across the coastal area of Côte d'Ivoire. And then also, in Peru, huge tranche of acreage in Peru. This is what we have done our best in the past, where we go and we move in early in places that are not hotspots, as Angus would say, and become hot spots. And that's what we're trying to do, identify new areas where we can go and pick up a large tranches of acreage, and then go take that high risk but then high-reward approach as we move forward. So we've rebuilt to the portfolio. The approach, I would say, the kind of philosophical approach, I think, on this executive team will be slightly different. We will be more measured about how we invest in exploration. We'll be more disciplined about the capital allocation. But saying all that, it will be a key plank of our growth strategy going forward. And really, today, what we're flagging is the start of a significant three-year program. If we look at that program, obviously, 2018, we are continuing to close out the seismic. Last year, we shot a record level of seismic across 3D, 2D and FTG. We did it at incredibly low cost because of the pricing environment. Some of that is carrying into 2018, but that's all in preparation of building a prospect inventory that you can then go and drill over a number of years. So we look at this more as a three-year campaign, rather than how many wells have you got this year or next year. And it's a multiple-layer campaign when you look at the active ventures and new ventures and even around the infrastructure areas. So lots of options ahead, all competing for capital, and that discipline will be applied as we decide which wells get drilled and when. But an exciting restock to kind of Tullow's drilling. Just in conclusion, trying to kind of summarize. I think we've transitioned smoothly and effectively to the new executive team. I think over '17, we've significantly de-risked the business, both operationally and financially. And that leaves us in a much stronger position to look for similar levels of performance in 2018. We said we would be, and we have been rigorous on our approach to costs, capital allocation and cash flow, and we've continued to fine-tune the portfolio. And we'll continue to see that as we continue to high-grade the portfolio and look for acquisitions, look for exits and continue to refine the assets that we have. And you'll see more of this overall approach as we go through 2018. In 2018, you'll also see us focus more on kind of enhancing and refreshing the portfolio. We think there's a lot more we can do to build the portfolio. We will be seeking options for growth. The current environment does lay out opportunities ahead of us and we've started to look at them. And most importantly, you will see us focus very heavily on shareholder return as we go through 2018. So 2017, exceptionally strong year, and we're looking to deliver the same in 2018.

A - Unidentified Company Representative: As we turn now to Q&A, [Operator Instructions]. And let's start with Brendan.

Brendan Warn: It's Brendan Warn from BMO Capital markets. I guess, while we're on Kenya, can you just talk about what sort of equity level, working interest level you're going to take into the project? And if I'm right with my math, that if - your current equity should be about $400 million per annum over a 36-month construction phase. Just kind of how you're going to manage that sort of upfront - or the 80% of the capital upfront. And can you also just touch on, again, related to Kenya, just the pipeline? Do you see that as part of your portfolio? Or is that something you'll look for external participants to provide?

Paul McDade: Yes, I mean, I think we've always said that our primary objective in Kenya is to define and move forward with the commercial project. So that's why we're there, and that's what the government kind of employs us, contracts us to do. So very much the message today is we've done that work and we are very focused, and that's where our focus will continue to be. I think as that gains momentum, you correctly highlighted, that we've always said that maybe 50% equity in this project is high for a company of our size, and we've made it clear to kind of all stakeholders that at the right time, we would look to reduce. In terms of what's the right level, it will be a balance between the whole value equation, the capital equation, in terms of how much we want to lay out of our capital. And actually, your last point, around pipeline in upstream, that balance, obviously, if we do move down the route in third-party funds of pipeline, then the overall CapEx drops quite significantly. So that then impacts - it has a kind of knock-on effect to, you're thinking about, what sort of equity you would retain and what sort of equity would you dislike. I think all of those points that you raised are quite interconnected. So primary focus is get the project underway and have something very commercial and you can move forward. I think the ability then to get to the right equity will be much easier.

Amy Wong: It's Amy Wong from UBS. Just a follow-up on Kenya, can you describe what kind of milestones we're looking for in between foundation phase development of the 210 million barrels as a starting point? And what's - how do we get us to the next phase, that gets us to the 560 million 2C?

Paul McDade: Yes, so we've kind of purposely not talked about phase 1 or phase 2 or phase 3 because we think it won't happen that way. I think what we see is we've got Amosing and Ngamia incredibly well defined and they're ready to roll, so we can move ahead with them. Then we have a number of other fields and additional areas within Amosing and Ngamia, which are not part of this core, and I think it will sort itself out. And I can see us actually gradually incrementing the development of the additional fields because it's onshore. It's not like an offshore where you have to kind of define phase 1 and then add another FPSO or do a major physical. You can do it very incrementally. And actually, more classical onshore, elsewhere we see in West Africa where we work - you would have some existing infrastructure. If you go and find something, you would just tie in and then you gradually build up kind of classical onshore. So I think what we're turn to do is say we need to make one step to get the infrastructure there and then you enter kind of classical offshore - sorry, onshore development, where you just incrementally build-up. And I'd say, our guidance at the moment is as we build up, we think the kind of plateau levels we'll achieve are kind of around 100,000 barrels a day. Maybe greater, but around 100,000.

Amy Wong: Just a quick follow-up. Any difference in terms of the reservoir characteristics between what you've decided to go forward first and the remainder of the resources?

Paul McDade: No, I mean, I think, obviously, these reservoirs, they vary in themselves, but - and if you stand back, they're kind of quite similar, I would say. Obviously, we're choosing ones. If you look at just the well count that we have already, we have a much denser well count in Ngamia and Amosing. And that, we understand, was better, so we're just moving ahead with them. But with time, we'll understand the other areas just as well and then we'll judge which one died and kind of went.

Michael Alsford: It's Michael Alsford from Citi. So keeping with the theme, Kenya. So could you just maybe update? Your partners, obviously, put out a release today regarding the planned development, but has chosen not to update resources, waiting for results on the water injection and I guess early production. So my question would be on your sort of 2C case, are you aligned across the partner group? Or do you take a more conservative view on secondary recovery within the development? And then just related to the resource base, so the 1C case of 240 million, you talked about sort of commerciality, it looks a bit low to finance, say, a pipeline of $0.5 billion. So I'm just wondering, can you give us some confidence that you think that the banks will come and finance the project with that 1C case of 240 million?

Paul McDade: Yes, I mean, I'm sure our partners, particularly Africa Oil, who do - who go to the granularity that we go, will come out and give their views and their commentary on it. As a JV partnership, we reasonably confident that these numbers can kind of reflect an aligned partnership with respect to resources. So when they ultimately come out and state their numbers, they might be slightly different, I don't know. But I think in a general sense, we have a partnership that are very aligned, both on the kind of resource levels we have and the way forward. You kind of mentioned the 210 million and the 240 million 1C. I think maybe it uses an opportunity to kind of differentiate. We very much see that 240 million is a 1C case, it's a downside scenario. And there's quite a range between the 240 million and the 1.2 billion in the upside. We'd like to see that range narrow as we go forward, and the phased approach can help us with that. But I would see the 210 million, I wouldn't associate it with the 1C. The 210 million is just a subcomponent of the 560 million. It's kind of looking at the 560 million and seeing within that where will we start. And obviously, we consider that we can make that commercial given the approach we're taking and we can get started. But the point being would you go ahead and put all this infrastructure there if you only thought there was 2 million barrels in total? Probably not. You're going to have - you can make 210 million barrels commercial, but the real - the upside price is then progressing that to 560 million, and hopefully progressing up to close to 1 billion when you look at their substantial upside. And we point out for a good reason that this oil in place is up to 4 billion barrels. When you start to look at percentages, these numbers are relatively small percentages of the overall oil in place that may be there.

Sasikanth Chilukuru: It's Sasikanth Chilukuru from Morgan Stanley. On sticking with Kenya as well, you have previously indicated a full cycle cost of $25 to $30 per barrel. With this phased approach, is it still consistent with that given you don't talk about CapEx for the next phase?

Paul McDade: Yes, I mean, obviously, the way we're doing it means that you've got more of the costs coming in earlier on, and we're looking at our kind of contracting and financing strategies to manage that. So I think if you stand back and look at the overall, the case where you develop 560 million or get up to 100,000 barrels a day, the previous guidance is kind of about right. Obviously, what we are doing is we - the bit we do know is we've done a lot of hard work on trying to drive the pipeline cost down and drive down the detailed cost for the foundation phase for the upstream. So we've given those numbers, that's what we think we'll be sanctioning on. We've obviously got feet to go to further define those. I think if you stand further back, the kind of previous guidance is about right for the overall.

Sasikanth Chilukuru: One more follow-up on Kenya itself. You talk about meeting government expectations. Just wondering, what are the consequences if you don't meet those expectations? What are those? And also sticking with the partners, have you had discussions with Total? Are they on board as well?

Paul McDade: Yes, I mean, I think the one thing, I think it's very good that it's actually realizing - it seems kind of simple, but realizing this oil was not ours, it belongs to the countries in which we work. And I mentioned when I was talking Ghana, again, when we set out in Ghana, we had the same conversation in Ghana. The government saw this is an opportunity for the country, and they wanted - it's only an opportunity if it's delivering cash and revenue to the country, and so they wanted us to move efficiently but quickly. And I think we're having a very similar conversation in Kenya. They want us to move quickly and efficiently. They don't want us to destroy value, they want us to create value, but they would like to see the cash flow coming into the country and then it - this is a finite resource and it will provide some benefit and that should help the economy of Kenya. So I think we are actually listening to the government. And as we've defined how we move forward, one key stakeholder, in our mind anyway, is always government, and you've got to stay aligned with what they require. But we've also got to have one eye on kind of shareholder returns, value and good oil field practice.

Mark Wilson: Mark Wilson from Jefferies. Moving on from Kenya, I'm going to check on what's going on there, there seems to be some questions. I was interested in that 2P reserves declined year-on-year, particularly as you approved the full field Jubilee plan. What does it take to bring through the contingent resources into 2P at well-by-well basis there? And then just add a housekeeping for Les, I think your slide on CapEx says there's $69 million moving over from 2017, in addition, I imagine. And just what are the decom costs as well this year?

Paul McDade: I'll take the resource and the reserve, and then Les can answer the other. I think the slide that showed around optimizing Ghana had the wheels. And what you're - if you look at these kind of numbers and look - go back to them, our presentation of them before, obviously, this segment, it's production is increasing. The then 2P part is gradually increasing. In one hand, it decreases because you produce it; and then on the other hand, it gradually - and then we've got 130 million, which is our 2C. And what's happened in the past and what will continue to happen is those 130 million will gradually, year-on-year, just kind of flow into the 2P. Because Ghana, the - although we call it Greater Jubilee development project, it's not really a project. It's a series of over, maybe, 3, 5 years incremental wells. And as we commit to batches of those wells and then go and execute them, our reservoirs will take the 2C associated with that batch and move it in, and so you go on kind of year-on-year. So what you will see is, over a number of years, gradually, those resources. And it can be a bit lumpy depending on what you do in any one year, yes.

Les Wood: And then to your other the two questions, Mark, the first one is in kind of supplemental notes on the diagram, $69 million was an adjustment to accruals that we'd had from '16 going into '17. And with respect to decom, I mean, one thing we've been doing on decom is a very good job of deferring where we can and optimizing costs where we can. So last year, in 2017, it was in the region of about $30 million. For this year, we have about $100 million. That's because, I think, you get to the point where, actually, if you're not doing some of that activity, you lose out on the savings by doing it along with someone else. So actually having equipment and vessels in the field, you do at the same time as other people. So actually, on a value basis, you do it more effectively. So the $100 million for 2018.

David Mirzai: David Mirzai, Deutsche Bank. You talked about you value free cash flow as much as investment for 2018. I was hoping you might be able to give us some idea of, under the current development plans, how much free cash flow you thought you'd be generating? And then secondly, on top, given where the forward oil prices, where I imagine is higher than your base estimates when you set your budget, can you give us some indication of excess cash flows, what you will do with them? I know you said deliver shareholder returns. Shareholder returns under the last management was spent somewhat differently than I expect you to.

Paul McDade: So maybe I'll give the kind of - my overview of how we're going to manage it, and then leave Les kind of talk about the numbers. I mean, I think as we came into the year, we've set out, as Tullow, last year of our capital discipline and cost management, et cetera. As we put together our budget for 2018 and we had kind of quite a bit of discussion with the executive team about what's the right balance, we kind of set ourselves a target that says, well, $50 a barrel. We want to produce free cash flow at $50 a barrel, so let's make sure we manage our capital allocation in a way that we can ensure we can deliver that. So that was the - we had the conversation that traded off capital investment with free cash flow at a price of $50. I think we've set our budget, which should delivered that. As you than see oil prices, if they stay in the mid-60s through 2018, then we'll just have an ongoing conversation about what is the right balance between the three things I mentioned, being down in terms of - you're going to generate free cash flow, you can then use it to pay down debt, you can use it to invest in things like a second rig in Ghana and you can provide shareholder returns. So like picking on the second rig, clearly, with higher oil price, so we'll consider the second rig. But as we look at that, the amount of money we would spend on a second rig, there's no point in having excess wells there. You made - what you're trying to do is just fine-tune the number of wells you need to fill those FPSOs, and then that depends on whether TEN turns out to be a 80,000-barrel a day FPSO or 100,000-barrel a day FPSO. So you will see us just continuing to navigate that and make judgments. But I think the important thing is as we make those judgments, it's kind of trying to balance off those three things as we navigate through 2018. So that when we're sitting here in a year's time, we'll be able to reflect back about, hopefully, we struck the right balance. Maybe just on the absolute numbers for...

Les Wood: Yes, so if you kind of take the ingredients that we've got in the plan for this year, and you assume a $60 oil price, a good estimate for free cash flow for this year would be about $500 million. And for every $5 increment, roughly, roughly, there'd be about $100 million actual free cash flow.

Al Stanton: It's Al Stanton, RBC. Much of the concentration has been on organic growth, but just a couple of things. You were saying that you feel pretty good about TEN, so I'm wondering if that has now been taken off the table as a potential disposal. And then we saw Hess write off their assets to the south of Jubilee and TEN. Would you consider something slightly less organic in terms of growth opportunities in Ghana?

Paul McDade: I mean, I think on TEN, I think often - I kind of ask at this point, just reflect back the rationale for our farm-down on TEN in 2012, '13, whatever it was, was very much because we had a massive capital project ahead of the year, which has two kind of negative things about it. One is major project risk and the other one is the bill you have to pay to get to first oil. And our endeavor at that time was to mitigate both the CapEx and the project risk. As it turned out, we, for the various reasons we've discussed many times, we didn't farm-down. Thankfully, we mitigated the project risk by managing the project very well and getting it onstream, on time and on budget. And we managed our way through the capital cost, and we're still working through that at the moment. So that was the rationale then. I think the rationale now for doing it on TEN or Jubilee or Uganda or Kenya or any of the assets, is just one of value. So we look at any of our assets and it's really about thinking how could you maximize the value from these assets, and we don't preclude - I mean, I alluded to portfolio management when I was talking. Okay, the big portfolio management last year was Uganda, but there was quite a bit of a small portfolio management. We exited Norway, we exited Netherlands, and Ian and Angus and the team on the exploration side did about $50 million, $60 million worth of deals last year in terms of net income. And you'll see us do that at all when - and whether it's big assets or small assets, we should continually keep an open mind on how we maximize shareholder value from those assets. So we don't - we're not putting something on the table and we're not ruling that it's a no.

Al Stanton: But with respect to adding more, I mean, you've mainly talked about selling, but would you look to...

Paul McDade: Yes. I mean, I alluded to kind of replenishing. I mean, as we up and down West Africa, places where we are, there are some interesting big assets, there are some interesting small assets. And we actively look at those, and we have been over the latter part of last year and we'll continually actively look at those over this year. And if we can convince ourselves that there's some deals to be done, which we've got one thing going on just now, but it's just a few hundred barrels a day. Not very exciting, but actually very interesting when you look at the value metrics, and we'll continue to do that.

Rafal Gutaj: It's Rafal Gutaj from Bank of America Merrill Lynch. So just a few quick ones. Firstly, on the gas cap at Ntomme. Can you just quantify the percentage of reduction there and then what that might mean for ultimate oil recovery if there's any impact? Secondly, on the well count in Kenya, it looks to me like you're recovering about 1 million barrels of well, assuming 20% of the wells are injected wells. How does that stack up against your previous estimates and how does that compare to your thinking on Phase 2? And then finally, following up on a similar pipeline, a 1C-related question. What kind of tariffs do you expect to incur now that you're basing financiers coming into this pipeline, with just 240 million barrels of 1C?

Paul McDade: Yes, just kind of walking through them in terms of - I think the first ones around the gas cap in Ntomme. I mean, I think we're starting to better understand Ntomme in terms of we have free gas, which we used to drive the oil out and ultimately we'll pull that down and sell it. There's been some movements on that, but nothing that would in any way impact our view of oil reserves. The vast majority of the value within Ghana is in oil, gas has a fairly minor value at the moment, anyway, in Ghana. So actually, I don't know the exact details of the movement and the size of the gas cap, but what I can say is we're - been really pleased with the performance in Ntomme in terms of its delivery. And the first well we're going to be drilling in the in-field campaign is in Ntomme, really because of that, because we're quite pleased about how it's performing probably above expectations. Kind of well count in Kenya, I think the reality in Kenya is there's a lot to learn about what these wells will deliver, which again is back taking a phased approach. EOPS is important because we will have, as we are working through the FID and the development, we will have, I think, 4 or 5 wells, on and off, producing consistently a couple of thousand barrels a day or higher. That will give us a lot of information. And we're going to be injecting there as well. That data will be paramount to understanding even in the first foundation phase. So probably, there's still some uncertainty actually and with variations on what each will deliver, some will be high, some will be low. And I'd say, were still trying to work out what the average is. So I think we put those numbers in there not to be too specific, but just to give people a flavor of this is the type of development. It's a very large well count type of development. And then on the pipeline tariffs, we've expressed the pipeline in terms of our capital, because what we've been doing at the moment is very much focused on how much cost can we take out of the pipeline and what could it be built for, and we've got quite an aggressive target there we think we can deliver. We haven't transferred the entire tariff because that will very much depend on the financial structure, which is in its infancy at the moment really.

Alwyn Thomas: Alwyn Thomas from Exane BNP Paribas. Can I just ask the capital allocation question a slightly different way? Your gearing is now 2.6x, and it looks like you're broadly thereabouts on the 2.5x gearing target. Can I just ask, do you have a specific net debt reduction objective this year and then anything above that is allocated accordingly as we've discussed? And my second question is just on Uganda, whether we could get an operational progress update there around FID and whether you're seeing any material cost savings.

Paul McDade: Yes, let me take the second one and Les can tackle the first. I mean, I think in Uganda, we continue to make very good progress. We're still targeting an FID around the middle of the year. And really, Total is playing a very dominant role. We are gradually moving ourself into the backseat a little. We're still formally an operator until we hand over the operatorship at the completion of the deal, so legally we're still operator, very much we are going into the backseat. So I think Total is doing a great job of driving both the pipeline and the upstream, and CNOOC are driving the southern area upstream. So there's not much to report other than pretty much on track and still targeting an FID around the middle of the year within Uganda.

Les Wood: And on your first question, I mean, we've got no specific gearing target. I mean, what I would say - there's a couple of things. One is, as I said when I was starting up, the $3.5 billion is still a big number. So whilst we've got a gearing at the right place, we're still focused on getting the absolute level of debt down. And of course, that helps doubling that you have less of financing costs, so I think that's one thing to say. And then I think the second is that when we went into putting a plan together for this year, it was very much set around the plan that was going to deliver good cash flow at $50 a barrel. So kind of the targets we set ourselves and the approach that we've got within our business plan works at $50. So that disciplined approach to our financial management then gives us the choices where things will turn out better, which they currently are, to give us the choice to carefully allocate our free cash flow, with debt being first priority.

James Thompson: It's James Thompson from JPMorgan. Just a couple of quick questions. In terms of production guidance for this year, a lot of it relies on the outturn from the wells you're going to be drilling in Ghana. Can you perhaps give us a bit more detail on your expectations for the wells at TEN, in particular? And then just secondly, in terms of Kenya, you set a pretty aggressive first oil target there. When in 2019 do you need to be FID-ed by to meet your 2021, 2022 guidance?

Paul McDade: I mean, I think on the wells, there's a range of outcome. I mean, the Ntomme well, for example, the first one, which obviously will have the maximum impact on TEN outcome for 2018 because it's the earliest one, it has the longest period it's going to be running for. We have quite a range. I mean, we have some - quite some upside expectations for that well that could come in, and we're kind of quite excited to see onstream and see how it's performing. But I don't really want to give kind of specific numbers for each well because I think it's - what's more important is getting up to 80,000. I think the moving parts at the moment for TEN are we're really holding the wells up well. We're still around about 70,000 barrels a day from the current well stock. Our expectation is that will decline as we go through the year, but the rate of decline is quite uncertain. So that creates some variability because that impacts the average. And then you've got the other thing coming - kicking in. If you've got a high-end well kicks in, say, in July, early August, that will be quite significant for the second half. And so the upside scenario is you don't see as much decline and you get a great result from your well and, actually, there you could exceed expectations. If it trucks down and we see the decline on the wells and we have seen a good average outcome, then we're sitting more around our kind of middle point on our range. So there's kind of two things driving that uncertainty, which is why we've come up with a slightly wider range than we normally would at this time.

Unidentified Company Representative: So what's the answer in - I think there was still a question on...

Paul McDade: Sorry. It's...

James Thompson: So the time frame on Kenya.

Unidentified Company Representative: Kenya.

Paul McDade: In Kenya, apologies. Yes, I mean, we have set ourselves in - I think one way to think about it is Uganda, we're thinking about as three-year from FID to kind of first oil, roughly three years, probably just a bit over three years. And I think in Uganda, we have a more complex project in terms of just because of the scale. You've got a 1,450, a 70-kilometer pipeline rather than a 750-kilometer. So we're hoping that we can reduce time for a couple of reasons. One, it's a slightly less complex project, but we're just gone after core plus pipe in a smaller CPF, not multiple CPFs. And of course, we've got the benefit every day, because Uganda's ahead of us. Other than lessons you learn as you progress through Uganda, you pass immediately across to Kenya because the projects are - they might be different in scale but technically they're - I think they're kind of almost identical. So I think three years would be a good outcome for kind of FID to first oil in Kenya. Less than three years would be an exceptional outcome. And if you can do the math, then you can work out - I think 2022 is a more realistic first oil, but we are going to kind of - I'd rather set really tough targets and really work towards them and see if we can get them. If you miss them and you're not far beyond them, then - I mean, we did that in Jubilee. We set ourselves a target of 2010. I think as we entered that project, my expectation was probably 2011 realistically, but we decided to go for it and we met it. If you don't set it early, you can guarantee you won't meet it, yes? So that's the philosophy. We're not trying to say there's a high chance we'll get to 2021, but we are going to endeavor to see what we can do. And if we get a 2022 first oil, we think that will be a good outcome.

Colin Smith: Colin Smith from Panmure Gordon. A couple in Kenya and then one on OpEx. Just in - I mean, Africa Oil published a TC number of about 7 50, 7 60 I think back in 2016. The number you published today is a couple of hundred million barrels less than that. I'm just curious as to whether that reflects a downgrade in the view about what Kenya was capable of? It's the first question. Second one, just going back to the timing on FID. If you are going to split the pipeline project in order to make that FID, it sort of feels like you would really need to be quite advanced in discussions with contractors and in financing at the moment to make that and organizing things like wayleaves and so on and so forth. So could you just tell us where you actually are with moving the pipeline part of the project along? And then separately, can I just confirm that the TEN vessel is now fully under financed lease and not included in OpEx anymore?

Paul McDade: I think the last one is easy, that's correct, on the TEN FPSO. I think on the resources for Kenya, we can only talk about our view of your resources, not our partners who've talked about view of resources. I mean, our view of resources historically has been, and we specifically said, we've got exploration uncertainty, we've got appraisal uncertainty. We're going to go and state it as a Pmean. We didn't come out and see a 1C, a 2C. We said let's kind of try and describe loosely what we have and we said a Pmean of 750 million. Now that we've got the data and we can, we feel, describe it more specifically, we actually feel that the description of 240 million, 560 million, 1,200 million is relatively consistent with our view of a Pmean before of 750 million. So for us, this is not a downgrade, far from it. We think in our overall resource base, the upper end is higher, the kind of midpoint is probably at similar levels. But clearly, there's less risk at the midpoint than there was when you're kind of pre-20 appraisal wells. Once you have the 20 appraisal wells, your risk - your understanding is greater, therefore your risk is less. So I'd say that's my view on the resources. The pipeline, generally, it will be the critical path, and we're seeing that in Uganda. That's the critical path of the Uganda project getting that right. I think the interesting thing in Kenya is that the area we're going through is fairly remote. And that helps because it's very unpopulated. One of the other routes we talked about many years ago was going through a Southern Kenyan route. The challenge with that is just, in part, some very highly populated areas, and that leaves some quite uncertainty in land ownership. And in the northern area, there's mainly kind of communal government land ownership, which actually makes things easier. And also, you have, if you've heard, the LAPSSET project, which was the kind of project that Kenya has always talked about. They've actually done a lot of wayleaves work for that project. So the project itself hasn't progressed - well, the birthing and some of the things have, I don't want to say it has, but the kind of routing of the project, whether it be a pipe, a route. There is quite a number of areas where we will - not always, but we will follow what was the LAPSSET routing. And there has been quite a bit of work done there on the land and the planning and the application of wayleaves. So that's really going to help us and our progress of our pipeline. And then the financing, we're kind of in - we have some discussions ongoing. We've got an adviser onboard, and that's something we're discussing. We kind of got held back a little bit, because we had a rather extended election period in Kenya. So that's a bit of a lost few months, where we weren't able to - because the government is going to be critical to the conversation. But I can reassure you we're absolutely reengaged with the government since we got back this year.

Job Langbroek: Job Langbroek from Davy. Just teasing out a little bit more on Kenya, please. You've got a 2C number of 560 million, and that's within an overall STOIIP of about 4 billion, which gives you 14% recovery rate. That looks quite reasonable relative to the - especially relative to the oil column. So can you just tease out a little bit, is that based on well count, is it based on reservoir quality or if there are any other factors involved?

Paul McDade: I mean, I think I don't know the fields in detail, but each of these fields vary field to field. So think the 4 billion barrels of oil in place we're seeing up 2/3, in kind of hindsight. I don't know off the top of my head what the kind of, let's say, the midpoint for the oil in place, but it will certainly be less than 4 billion. So the - if you've taken an average recovery factor for the midpoint, it will be higher than the number you just quoted. But it will vary field to field. And even within the fields, area to area. And I think what we've seen in Uganda, and I think we've seen it - started to see it in Kenya, is that if you think back to Uganda, we stopped drilling and we were at about 900 million barrels of 2C. And we may have drilled 1 or 2 additional wells, but not many, and we found that the 2C moves up to 1.7 billion. And ultimately, in the end game, because we had so much time, we eventually got our auditors to catch up with us and they booked 1.7 billion, and yet we didn't drill any additional wells. And that was really all about continuing to analyzing, continue to get confidence in the modeling of the reservoirs. And I actually think that's back to momentum. I think we'll see the same in Kenya. I feel that we maybe a bit cautious in Kenya, but that's fine. It is not cautious on giving what we know today. I think if you step forward 3, 4 years, we will know more, especially through the EOPS and I think we're more likely to gain confidence about the way in which we can recover the oil from Kenya. So again, I'm optimistic about - and we've got the right numbers for today, but I'm optimistic that we're setting our look at 670 million barrel upside from the 2C.

Unidentified Company Representative: Could we go any questions on the conference call, please?

Operator: [Operator Instructions]. We have no questions of the phone line at this time. I'll turn the call back over to you for any additional questions.

Mark Wilson: Just one follow-up, it's Mark Wilson from Jefferies again. As I recall, the EOPS in Kenya also had a kind of a government commitment to upgrade the roads and the bridges, particularly because it's a very long way to get supplies in and out. Is there any update there?

Paul McDade: You're quite right. I mean, of course one of the benefits we saw of getting ahead with EOPS was the fact that the government was going - willing to commit to, because there's a limit to the number of trucks we could move unless that road was upgraded. And the time we really need the road is for the full field development. And the whole philosophy was if we do yield and get it there, we'll then know at least it's definitely going to be there for the full field. Progress has been made. I mean, contractors were mobilized. Some upgrade sections have been watched, so it's kind of work ongoing. Because of the extended election period, you saw many things in Kenya stall, and that was one of them. So we were not as far forward both on the EOPS. I mean, we had kind of hopes that we may have been able to get EOPS up and restarted kind of either late last year, early this year. I think we will start production in EOPS later this quarter, early next quarter. So we're behind on that. And similarly, the road is behind. But the road is in a shape that once we are ready to go, we can start moving modest amounts of oil roughly with where they are today, but we'll be continuing to put pressure in the government to make sure that they complete the upgrades that they've started.

Unidentified Company Representative: Okay. If there are no more questions, thank you very much for coming along. We do have our EVPs here, Angus McCoss, our Exploration Director, plus a number in our finance team, if you have any of you have an a for the questions you like to discuss. But thank you very much for coming along.

Paul McDade: Thank you.