Tullow Oil plc

Aidan Heavey - CEO Ian Springett - CFO Paul McDade - COO Angus McCoss - Exploration Director

Dan Ekstein - UBS Alex Topouzoglou - Exane BNP Paribas Theepan Jothilingam - Nomura Brendan Warn - BMO Capital Markets Caren Crowley - Davy Rafal Gutaj - Bank of America Merrill Lynch Sanjeev Bahl - Numis Securities Michael Alsford - Citi David Mirzai - Societe Generale Tom Robinson - Deutsche Bank James Hosie - Barclays Thomas Adolff - Credit Suisse Alessandro Pozzi - GMP Securities Dragan Trajkov - Oriel Securities Anish Kapadia - TPH Gerry Hennigan - Goodbody Stockbrokers

Welcome to the full year results. What we'd like to go through is how we've reset the business.

Last year, obviously, was a very challenging year and that was reflected in the results. The oil price collapse, I think, took most people by surprise.

And I think this creates a time of great uncertainty. I think if you look at the so-called experts and their views of oil prices, you've everything from $30 to $200.

The mean of that is about $115. So it's quite a hard thing to actually plan a business, going forward.

So we took a very conservative view. We took a view that the oil price will be $50, maybe even drop even further.

So we set about, very early on and we started last year, adjusting the business to be profitable and to work in a low oil price environment and despite what people seem to think, this is not the end of the world. The industry is very good at adjusting and it has done so numerous times in the past.

What we did is we obviously started talking to our banks early. We started looking at our overheads, our structure.

We started looking at our capital programs. The first thing that you do is you cut your exploration programs.

You get rid of capital projects that don't work at these prices. You look at your balance sheet.

You take out all the costs that are uneconomic at these low oil prices. And you really focus on making sure that your business is a very successful business or you can be successful at this low oil price environment and that's what we set about doing.

So, by the end of this year, we will have a business that will be efficient and works at $50. We took the decision to suspend the dividend.

We looked at our overhead costs and over the next three years, internal overhead costs, we will save about $0.5 billion. The teams will be continually looking at cost savings and the cost savings will be internal.

We're also looking at external cost savings. Paul and the team will be getting stuck into the operating costs.

So it's an ongoing process to keep at the cost structure. So we're pretty comfortable where we're right now.

We're comfortable that we're funded through first oil in TEN which is a major milestone for us. And our focus as you'll see, Paul will take you through the very strong production assets that we have and take you through our TEN development which is going extremely well.

So I think one of the key things that Tullow has in its favor is a very, very strong asset base. I think and I'm not just saying this myself, but I think we have by far the best asset base of any company out there and we have great flexibility in that base.

On the exploration front, we're not giving up exploration, but you have to be sensible. And we're focusing our exploration programs around our existing producing assets or the very low cost areas like East Africa.

But we've also got a growing business and growing cash flow, so we have to look to the future. Angus and his team of explorationists will be looking at exploration prospects that work at this low oil price environment and we'll be building that portfolio up for the future.

Ian will take you through a bit of the cost reductions that we've gone through. But as I say, it is an ongoing process and we will be cutting more costs as we go through.

I think the other thing which is very important and again, in this industry, when you look at big projects like TEN, you cannot have overruns, you cannot have delays. So the focus of the team is delivery.

And what we have been doing is making sure that the major projects are delivered on time and on budget. And think, Paul will take you through that.

So, I'll now hand you over to Ian, who'll take you through some of the financials. Thanks.

Thanks, Aidan and good morning, ladies and gentlemen. As Aidan said, it's all about taking action, taking tough decisions so we can manage our business on a going-forwards basis.

And the first thing, really is actually managing our capital, allocating our capital to high margin-generating assets in West Africa, real focus there on Jubilee, on TEN. And these assets are assets which have very low break-even prices, even at today's oil prices.

Also as Aidan said, very much not giving up on exploration, but a recognition that now is the right time to cut back significantly as we had indicated previously to focus less on high-cost exploration, but to focus on low-cost exploration and building a portfolio of options for the future. And the TEN project as Paul will talk about in some depth later, is very much on track and on budget to deliver significant additional cash flows from mid-2016.

Internally, we're having a strong look and we started this project back in November time, to really start thinking about how we can simplify our internal structures, how we can be more efficient, how we can reduce Tullow cost, Tullow people costs and all the costs in terms of travel and offices and contractors and consultants that go with that, but to reduce the cost of Tullow's own operations which as well as challenging costs externally as well. We expect a saving of around $500 million over the course of the next three years, beginning to kick in, in the second half of 2015 and then more fully in 2016 and 2017.

Again, these are costs associated with Tullow's internal operations. And these are separate to cost reductions that we'll achieve through challenging our contractors and subcontractors around operations and CapEx.

As you might imagine, though, the Tullow people as they work within the business, are working on capital projects, they're working on operations and they're also part of the Tullow residual corporate costs in terms of managing the overall Tullow business. We expect roughly and these numbers still to be finalized, but perhaps about 50% of the $500 million reduction will flow through in 2016, 2017 into reduced CapEx.

And then, perhaps, about 25% flow through into reduced OpEx and about 25% into reduced net retained G&A, reduced net corporate costs. Aidan also mentioned about suspending the dividend.

Think of the dividend, really as another cost lever to pull. We think it's both wise and prudent, in the low oil price environment.

When we set the dividend and we - when TEN - sorry, when Jubilee first came into production we doubled the dividend and we've maintained that dividend. And that dividend was appropriate, I think, in a $90, $100, $110 barrel world.

Clearly in a $50 barrel world then dividend like costs like CapEx, is something you need to look at. We believe that it is both right and prudent to have cut the dividend and give us additional financial flexibility.

Cutting the dividend, reducing the cost saving about $180 million per annum and if for example we were to think today of cutting the dividend, suspending the dividend through to TEN first oil for example that would save us, in that period through to TEN first oil around about $300 million. All these actions give us this financial flexibility.

The debt facility headroom that we had at the end of 2014 - and we had already begun to work on that in 2013, 2014 with diversified debt with the two bond issues with refinancing the RBL and terming the debt out and I've got a slide that will give a bit more information on that later. But there was significant headroom that we start with and with our funding projections, at these lower oil prices, we're still well-funded through TEN first oil.

When you add to that the fact that we also have good hedging facilities in place, we've got about a $500 million mark-to-market position over the course of the next two or three years from the hedges we have in place at the moment. And that provides revenue projection, protects our revenues, protects our EBITDA and actually gives us RBL debt capacity as well.

So when you take into account the reduced CapEx, the reduced costs, suspension of the dividend, the facility headroom that we've got, we're well-funded through to TEN first oil. And importantly, we have no plans at this point in time to raise equity.

We're well funded, we don't need to raise equity. We also have very strong and supportive banking relationships.

We talk to our banks all the time. We're very open and transparent with our syndicate.

By being open and transparent, we build trust with our banks. We have redeterminations with them as part of the RBL every six months, routine redeterminations where we look at future cash flows.

We share cash flows, we share reserves and we share production forecasts and that process started for our March redetermination already, that's going very well. Inevitably, we'll also talk about our future forecasts which they've already got.

Inevitably, a conversation will come up around covenants. We don't really see that being an issue because our funding is so strong through TEN first oil.

So in summary, taking action, well-funded through TEN first oil, no plans to raise equity and ongoing conversations with banks all very positive. Next slide is the results summary itself.

Clearly, whilst we continue to be underpinned by strong production in West Africa which Paul will talk about later, our sales revenue, our gross profit and our cash from operations has been impacted by a lower oil price versus last year and also lower oil and gas production. And we'll see a little bit more on the next slide.

And the gas production impacted by asset sales as well and of course, we suspended the final dividend. But overall the big, obviously, difference, if you like, from 2014 to 2013 are the various exploration costs written off, goodwill impairments lost on the sale, etc.

which Aidan alluded to and we'll talk a little bit more about those on this next page. If we compare as we usually do, our net income from 2013 to 2014 and the profit in 2013 to the substantial loss in 2014 and you can see that we talked about lower oil and gas prices, lower oil and gas production.

But the big impacts there, clearly, are the exploration write-offs, the impairments, the disposals and the goodwill impairment. Just to briefly talk about those, even though we've mentioned those in our IMS and trading statement, French Guiana, in terms of exploration write-offs, we've written off our position in French Guiana.

We still believe it has value, but we believe that in the current environment that such a deepwater operation is appropriate to be written off. We've also written off assets, certain of our assets in Mauritania, so exploration licenses on the Fregate well as well as our Banda asset which we're not proceeding with now.

In terms of impairments, this is really mainly around our mature assets, principally assets in the UK, Netherlands, Central and West Africa. It's a reflection of much lower oil and gas prices as well as higher decommissioning costs.

And in Gabon, we've also written down, for the moment, our interest in the Onal license. We're in the middle of negotiations with the government there in terms of license terms.

But our view was that from an accounting perspective at least our title on that asset wasn't sufficiently clear to enable it to remain capitalized. But nevertheless, we're confident that a new production license will be issued and Paul is actually and will talk later, is confident that, that will be both, A, achieved and B, confident to incorporate on our production in our 2015 production guidance.

In terms of disposals, the main items there as you are aware, are the write-down began the contingent consideration, $370 million as well as certain asset write-downs connected with the UK asset sales. And the goodwill impairment is a reflection, if you like, of the value of the impairment that we now believe is appropriate, that was given to the Spring acquisition.

And this reflects a reassessment of the risk resources and a dollar-per-barrel value of those resources and results in $133 million write-down. Capital, we're guiding $1.9 billion for 2015.

If you look at the chart on the left-hand side, you can see the significant cut that Aidan mentioned on exploration, $200 million and whilst there is an increase in D&O expenditure, that's much to do with the big effort on TEN as we approach first production in the first half of or by mid-2016. So the big chunk of costs in the $1.7 billion are Ghana, TEN in particular as well as Jubilee, $1.3 billion.

We also have costs in there of around $200 million around maintenance CapEx in Central and West Africa as well as development costs in anticipation of FID, in East Africa. So overall, $1.7 billion.

And once TEN is onstream then we're probably looking at, just to give you a number to think about, around about $500 million of maintenance CapEx as being what we'd normally spend, once TEN is onstream per annum. So you're probably talking about $200 million Central West Africa and $300 million, probably, $200 million is Jubilee, $100 million TEN, let's say, on ongoing maintenance CapEx for those assets.

And that would the sort of CapEx we'd be wanting to spend and really, everything else after that is discretionary beyond TEN first production. We also as Aidan indicated and Paul will probably talk a little bit more, will be working with our partners.

In Central West Africa, we've taken on board their budgets for 2015. They're probably having similar conversations to ones we're about how to reduce our costs and so with both of our partners for Central West Africa as well as talking to contracts and subcontracts generally, we hope there will be some downward pressure on that $1.9 billion.

It's a number that we've already shaved and cut pretty hard. But nevertheless, we see $1.9 billion as maximum and hope it's more like $1.8 billion or $1.7 billion.

From a debt perspective as I said previously, we really addressed our [inaudible] base in 2013, 2014, diversifying with the bonds, refinancing our debt. Our earliest maturity in our debt is 2017 and that's a revolving corporate facility which we refinanced in 2014.

So it's only three-year facility, but our debt is well termed out. It's also important to note that whilst the RBL is price sensitive in the sense that the RBL debt availability is a function of future cash flows, future production and future oil prices, our corporate facility and our bonds are not price sensitive at all.

So we've got $2 billion of facility in there which is not connected to the oil price. And as we talk to our banks, at least at this stage, the banks always look at the oil price assumptions, the price deck used in the RBL on a very conservative basis anyway and had been using circa $70 a barrel and we still think, in terms of our next redetermination, it will be still well into the $60s.

As we go well into that redetermination, we feel we're in a pretty good place because we actually had more, if you like, PV in that facility, more kind of value than our commitments. It will come down a little bit because of lower oil price.

But, at the same time, we expect that to be offset by an increasing value attributed to Jubilee which currently is in there at - effectively, it's somewhere between 1P and 2P, it's about 1.25P. And we expect that to go up now we've got good four years' worth of experience on Jubilee.

So, overall $2.4 billion of headroom in 2014, a set of debt which is well termed out and plenty of access through TEN first oil. One thing that also helps us, an additional slide here, is just on hedging, just to give you a bit of a sense on hedging.

Hedging is something which we've been doing, on a consistent basis, for a number of years now and we do hedging, what we call on a ratable basis. We don't pretend to be oil price experts, if we were we would probably be in different jobs.

But we're looking very much to protect ourselves from volatility, protect ourselves from downside and what we do is we put in place primarily some different instruments. But the primary instrument is what's called a collar and the advantage of a collar if you like is that it gives you both downside protection, so, for example, in 2015 we're protected down to $86 a barrel, but at the same time, it retains access to the upside.

So with that downside protection of say $86, the upside of the collar, the top end of the collar might $130 for example which means that any oil price below $86, we get $86. If the oil price is, say, $100 we get $100, $120, we get $100 and we only lose out if the oil price is over $130.

On occasion we also sometimes, we buy what we call a three way or we actually bring some of the upside back as well, if we think that's what we can do, should do and it's often very cheap to do so. On that basis, this program has a really good impact in terms of mitigating the downside and our revenues.

And also because the banks use that in the calculation of future cash flows, it also enhances our debt facility as well. So $0.5 billion mark-to-market is our position at the end of 2014.

It's a good place to be. Our final slide in summary is that as Aidan said, it's all about resetting the business, having a confident outlook during this period of low oil prices and taking key decisions and key decisions early.

Good news is we had already taken some key decisions around our banking and our refinancing. At the same time, all that is underpinned by high margin production, cash flow.

We've got stable performance Jubilee with further upside which Paul will talk about. TEN's onstream, it's very much on target, on budget.

So TEN will be onstream middle of 2016 and that will contribute very significant additional cash flow. Our West African assets are economic, down to some pretty low oil prices which Paul, again, will talk a little bit about.

And we continue to work hard, particularly on those assets to drive down the cost base and optimize production. We talked also about efficient allocation of capital, capital, particularly exploration, where we've taken our budget down to $200 million.

Angus will still talk about how, although it's down at $200 million, it's a function of drilling in lower cost places like Kenya, but also still building that portfolio for the future. So we're still very much - exploration is still part of our DNA, absolutely and clearly, the focus would be producing assets on high margin production and development assets.

We've looked through balance sheet in terms of the current environment, in terms of what makes sense at these sorts of oil prices, both from an exploration perspective and also asset impairments and we talked about the charges there. And then from a funding perspective, we've entered this downturn with a robust balance sheet.

We've taken decisions to enhance our flexibility around CapEx, around costs, around dividend. We therefore funded through TEN first production and we don't need or we have no plans, to raise equity as a result of that, of those actions that were taken.

So overall, we believe we're in good shape. And we're both well positioned to manage through current oil prices, but incredibly well positioned if conditions improve.

With that, I'll hand over to Paul.

Thanks, Ian. Morning.

I think as Ian mentioned and Ian's reinforced, we did move early in the process to reset the business for the current environment. And it has put us in a pretty strong position and I'll go through where we're with the specific assets.

We do have an excellent production and development business and I'll highlight how robust that business is, even down at current oil prices or lower. And then importantly, this period, whilst it's difficult, is actually an opportunity.

What you've got to do is grab the opportunity part of low oil prices and make sure you make the most of it while it's here. I'll kind of talk a little about how we're trying to take that opportunity and what we're doing within the business, Ian's alluded to some of it.

Tullow has a very robust production and development business. That has been the case for quite a number of years.

We've got a strong, stable, high margin oil production profile that's got significant growth potential. We've got assets that are robust down to low thresholds and low oil prices and have low operating costs and I'll pick up on that.

The investment case for these assets is strong. So in areas like a Central West African or Jubilee, actually, the investments were continuing to make into those assets are robust to prices lower than where we're the moment.

And we've always had a very strong operating capability which is very important that we're then executing those projects or taking the opportunity of the environment and importantly, keeping control of our key assets. We've seen significant progress across the whole asset base in 2014, we got some key milestones in 2015 and I'll go on and talk about them.

In terms of Group production, West African production performance last year was within guidance. And we're guiding similar levels of production for 2015, so guidance has been well flagged at 63,000 to 68,000 barrels per day.

North Sea production last year was within guidance. It was obviously impacted by successful sales in the Southern North Sea of Schooner and Ketch and also with the sale of the minor interest in [inaudible].

In 2015, we're guiding 6000 to 9000 barrels per day oil equivalent in the North Sea for the full year. And then as you know, we've already signed an SPA for some of our Dutch assets that will complete during the year.

And then, we'll adjust guidance down once we know the completion date for those assets completion. Really as we look forward in 2016 we start to see the impact of TEN coming through and how substantial that is.

As Ian and Angus have flagged, expecting to get the West African high margin oil production up to above 100,000 barrels per day in 2017. If we look at the Central West Africa portfolio, in the past it's always been there.

It hasn't had a lot of attention. Getting a bit more attention now which is quite right, given the cash flow that it spins off.

It's stable. You can see the track record of keeping that at or around 30,000 barrels per day.

We're forecasting 30,000 barrels per day in 2015 and in 2016 from those portfolio of assets. The big benefit there is you have a portfolio, got 24 non-operated fields with multiple different operators.

Actually, we can then have just a small focused team who interact with those operators and actually transfer learnings between the operators and actually push the operators on areas such as operating cost. Currently, operating costs are around about - cash operating costs are around $15 per barrel on average for those fields.

It varies slightly from field to field, but that's the average. We're working with the operators and as you'd expect, they're pretty active in looking at ways to drive down that operating cost.

So it's pretty attractive at the moment, but we feel that we can drive it down further taking the opportunity of the period we're in. Contractors, service companies are much more open to be having discussions about sustaining contracts even if they are slightly lower margin in cost.

Also, their cost base is reducing so we're basically in some ways, just asking them to pass on the reduction in their cost base through our contracts with them. The assets have low cash break-even levels.

If you look at this portfolio, there is a whole - it's probably with no further activity, the cash break-even's down at $30 per barrel or even below $30 per barrel. So you've still got positive cash flow down to levels below $30 per barrel here.

If we look at a full-cycle investment case, where we're investing $200 million per year to sustain 30,000 barrels per day that still has a cash break-even of around $40 per barrel. So very robust and adaptable to prices at $50 or lower than $50.

Again with regard to the investment in 2015, we have allocated in the $1.9 billion that Ian talked about $200 million as we've spent in the past, over the portfolio, that's been allocated. I think in reality, our operators on those assets are looking at trying to fine-tune that capital program for 2015.

So I would see $200 as an upper limit, rather than necessarily a target and we would expect maybe that to start to come down a little bit as they look at activities, look at the cash flow impact in the short term and maybe start to slide some of those activities to the right, if they're not needed today. So a fine balance between protecting revenue and optimizing the timing of capital expenditure, not whether you do it, it's just about the timing.

If we look at Jubilee, had an excellent year last year, exceeded production guidance, despite an additional probably six or seven months of delays to the gas plant. When we sat back and set our guidance at the beginning or at the end of 2013, we had expected that gas plant to be on in about May and despite the fact it didn't come on until November, the team still managed to deliver over 100,000 barrels per day from the field.

A lot of that was down to the very high operating efficiency from the FPSO and the subsea equipment in the wells, delivering high pre-tax operating cash flow last year. At year end, finally we managed to export some gas to the gas plant.

And the good news is that, that has been relatively stable, around 50 million to 60 million standard cubic feet being exported off the FPSO every day. The plant has gone through its final audit, it's looking in reasonable shape.

There is some checks and things to be done, but no real issues with the plant as we can see. Really the next step in 2015, is to ramp up the export to the gas processing plant onshore.

And really, the target there is to get the export over 100 million standard cubic feet per day. The key factor there is really the power stations at the VRA, taking more gas.

So it's more the demand side now, they're working on that and actually are hoping to be taking up to 90 million standard cubic feet per day, almost imminently. So pretty good news on the gas export that has a knock-on effect to our gas injection.

We can start to now decrease the amount of gas we're putting into the reservoir which then allows us to start focusing on actually ramping up the fuel production rates. That will be assisted, we're planning a couple of infill wells in the year.

So between adding well capacity in areas which have lower gas ratios which means we maximize the use of compression and the combination of less gas injection and the additional wells, we expect to be able to ramp up nearer to or at, the kind of fuel capacity as we get towards the end of 2015. As I say in the slide, it's all about protecting the long term value of the asset.

This is a long term value asset. And you're always balancing off just short-term revenue against protecting long term value and long term revenue.

We've guided similar levels of production in 2015, but as I say, we hope to get towards facility capacity at year end. Again, on operating costs, in Jubilee they're around $10, maybe just lower than $10, per barrel.

And that's our all-up cost. That's the cost of a full operation in Ghana loaded onto that 100,000 barrels per day and some of our corporate costs coming from elsewhere in the Group onto Ghana, where we provide services.

Actually, $10 a barrel for a field such as that, that doesn't have synergies from multiple fields in the area, is actually a world-class operating level. But what we're doing, again taking the opportunity, number of areas, Ian mentioned we're looking at our organization.

And the overhead that gets overlaid onto Ghana is a point Ian makes, if we reduce our overhead cost then there's less cost will flow through to Ghana, therefore, the operating costs will come down. We're already talking to our contractors about sharing cost savings and them being more efficient at $50 per barrel.

So both of those are areas that we're looking at in 2015 to try and deliver lower operating costs as we progress through 2015 and take the benefit of that late in 2015 and through 2016. And really I want to focus on that because the next big step is when TEN comes onstream in the middle of 2016.

And then as we get towards 2017, we've got a relatively fixed cost base within Ghana. Obviously, there is a number of items which are variable, but there is a large fixed element.

And what we'll be able to do in 2017 is share that fixed element over 200,000 barrels per day across Jubilee and TEN, rather than just 100,000 barrels per day. So again, lots of opportunities over the next one to three years to drive down what is already a pretty good operating cost within Ghana.

If we then go on and look at TEN in terms of status, is a critical project for us as Ian and Aiden mentioned. We're absolutely on track for first oil in the middle of 2016 within budget.

And the project is - as we've flagged before, at the of the year we had a target to be over 50% complete and that's exactly where we're. The initial 10 development wells which are planned to be ready for start-up, have already been drilled and the results from them, from a subsurface perspective, fully support our most likely reserves that we're planning to develop with TEN.

In fact, if you look at the downside scenarios we had on TEN as you always have a range around your mid-point, we see the lower end moving up with some of the positive outcomes we've had from those development wells. So, looking more to the upside rather than a downside after 10 wells drilled.

Completions in those wells will be underway within the next month. And actually, given we have rig capacity, we're looking at maybe adding a further two wells this year to TEN which just means we'll have additional well capacity at or around the startup of the field, so ahead of the curve.

The FPSO was the picture at the front of the pack. It's making great progress as you can see from the physical picture.

Actually, we had the benefit in Jurong of having - we were meant to take it in for two or three separate dry dock periods is when they can do certain things. Actually, we took it into dry dock because of rescheduling.

We were able to keep it in dry dock for, I think it was, about 3.5 weeks or 4 weeks, rather than the week planned which meant we got a lot more done within dry dock and it probably won't have to go back in again. So that's really helping us get ahead of the curve on the FPSO.

It's very much we have an early curve and a late curve as you'd expect as you're managing the project and on the FPSO, we're very much on the early curve and that dry dock period has really helped us there, keep ahead of the game, which is good because that gives you flexibility to really make sure that when it sails away in the fourth quarter 2015 as you'll know from following major projects, one target is the sail-away date to get it out of Jurong and heading to Ghana. The second, but sometimes more important, target is make sure when it sails away, there is not a whole pile of work still to be done enroute and within country.

You want all the work done in the shipyard, so that's very much our target and we're looking as it's sitting on the early curve at the moment for that. The other major milestone on TEN this year is starting the subsea installation.

We'll have a fleet of vessels going into Ghana in the third quarter reasonably early starting reasonably early in the third quarter. And the key factor here is obviously the vessels turning up which is usually not the bigger problem is making sure you have all the equipment in country for them to install.

As I say, all the component parts that are being fabricated in various parts of the world are all on schedule. I was over visiting in Houston with FMC which is a key supplier and again, they've been making really good progress, keeping ahead of the curve in terms of their delivery schedules for the infill installation.

So whilst there is a lot of significant activity ahead of us, we're feeling as confident as we could be that the project will be delivered on schedule with first oil in the middle of 2016. East Africa, we remain focused in East Africa on maximizing the potential of Kenya, Angus will talk a little bit more about the exploration phase, optimizing the Kenya and Ugandan developments and ensuring that both projects benefit from a shared and optimized pipeline.

So that's really the whole over-arching focus of East Africa at the moment. The appraisal of Lokichar Basin is going very well as you will have seen from the statement, I think it was January with some of those appraisal wells coming in with very high net pays.

We've got other appraisal wells ongoing at the moment. And importantly, we've just got underway with an extended well test program in the major accumulations.

And that will not only give us sustained production performance, but actually will give us interference testing which means that you'll be measuring the response to the test in surrounding wells. So gives you an idea of the communication across the reservoirs which has a big impact on the recovery factors.

Positive outcomes from the EWT should give us more confidence to move up the lower end of the recovery factor range. It's certainly something that's been very successfully applied in Jubilee and then was successfully applied in TEN and in Uganda and now we're underway in Kenya with the same.

So really looking as we go through 2015, to really increase our degree of confidence and develop [inaudible] in Lokichar. And I say, Angus will talk about the exploration portfolio in Kenya.

In Uganda as you're well aware, we've had really major success in driving down capital cost. That's even before the current low oil price environment which should - if you were going out to the market you would see I think further reduction in a competitive environment.

But just from value engineering optimizing design, we drove down the Uganda cost, it's down about 1.5 billion barrels - sorry, $1.5 billion net to Tullow pre-first oil. If you take that as an over-arching dollar per barrel, it's about $6 per barrel development CapEx which is world class.

And now, the focus is on transferring all those learnings over to the development work that we're doing in Kenya in preparation for the development there and also onto the pipeline, trying to drive down the overall cost of the pipeline by optimizing both its design and its routing. You'll maybe have seen some press coverage.

Basically, we now have all parties absolutely focused on what is a critical path for this overall project which is the export pipeline. The Ugandan and Kenyan governments are now holding hands.

They've appointed jointly a technical advisor to look at the design, look at the routing, look at all the work that the JV partners have done and are very much getting focused on what is, in essence, a 300,000 barrel per day export project, so massive revenue income for the countries. Really, all our focus is on working through 2015 and 2016, making sure all the work's done and then that gives us the option, if we want to sanction an FID, the East African project and probably towards the end of 2016.

In terms of reserve resources, we have a very robust portfolio of reserves and resources as you know. This year we've seen a dip in the resource state, that's predominantly Banda and Kudu.

We flagged earlier that with the capital allocation push these projects were - they're certainly non-core to Tullow and we've decided, actually, a focus of our capital allocation should go onto as you'd expect, Ghana, TEN, Jubilee, Central West Africa and some exploration. Therefore, we basically relinquished the Banda and Kudu interests.

So it's quite a big headline, it's about 150 million barrels of oil equivalent of resources. But remember, it's gas and the respective value of that gas was relatively modest.

So big barrel numbers, but relatively low prospective value. Really, the focus here is on adding further resources in Kenya as we progress the appraisal program, Angus will talk about the exploration program and then as I mentioned, following our track record of commercialization, focusing in on East Africa and getting it ready for the next phase of commercialization.

And really, this is the portfolio that underpins that low cost, high margin oil robust production and development business. With that, I'll hand over to Angus.

Thank you, Paul. Good morning, everybody.

Exploration, appraisal, well, we're making our reduced exploration budget of $200 million really work for us by focusing on our exciting low-cost place that you've heard Aidan talk about, but also focusing on our long term options. You see here, on the slide here, a picture of how we're adapting our E&A strategy to the current environment.

In fact, we've been adapting to the environment over the last two years. If you remember, in 2013 we started a shift to the shelf and I announced that this time last year at this very same meeting.

So we always like to be a bit ahead of the curve in terms of E&A, but also throughout the business as you've heard from previous speakers. Now you might recognize the form of this chart, it's a zoom in on the corporate strategy.

At the center there, you see the exploration and appraisal green circle and to the left of it, the higher margin production cash flow. Now of course, that's limited at the moment to $200 million of focused investment.

Historically, that's delivered 1.45 billion barrels of oil equivalent principally oil actually in the 2007 to 2014 period. Just to give you a sense of what that rate is, that's the rate of about 500,000 barrels per day.

So we have been delivering a lot of oil through in towards the monetization options and portfolio management side of the business. And you've heard from Paul as to how we're monetizing the bulk of that oil through our exciting developments in Jubilee, TEN and East Africa.

Now you see that this chart then branches into two colors. The top half focuses on our near-field exploration and appraisal, in purple and the bottom half focuses on the golden new frontiers.

Let's look at the top half of this diagram, first. We're focusing there on high margin oil.

We're extending production in our core assets because in the industry, we know that big fields tend to get bigger. And I'm going to show you an example of how we're getting after that upside in Ghana.

We get feedback from these campaigns, positive and negative and we feed them into the capital allocation process at the beginning of the cycle. Looking at our new frontiers, also get feedback from those, positive and negative.

You'll recall, we went after the Jubilee play. It turned out to be a bit of a Jubilee diamond, bit of a rare diamond and perhaps we could have stopped that campaign a bit earlier than we did.

That's a lesson learned, a lesson that we take forward with us. But as I said, we started to act on it a couple of years ago and we executed a shift of emphasis towards low complexity.

What we realized was it was the complexity of the wells leading to the high cost. So we've cut out those complex high cost wells from the program and gone for low cost onshore and simple offshore plays, on good commercial terms.

All-in-all, we have and still have, an excellent oil acreage portfolio I think, leading in the industry and we continue to build that portfolio for the long term. Just taking that from more of a geographical perspective, we have a great set of low cost, high value E&A investment options.

You see them round the globe here. In Africa, bottom left-hand corner, our Atlantic margin plays, top left-hand corner, the Carribean-Guyanas Atlantic margin plays, top right, the Norway Atlantic margin plays and the bottom right, the East African onshore rift plays.

We structured this chart so that each of these areas has three labels, if you like, numbered 1, 2 and 3. The top is the license activity ongoing in these areas then the frontier wildcatting, the drilling that we do in these areas and then number 3, the de-risked core E&A, where we've taken the risk out of the basin by establishing it's an oil prone area.

But what I would really like you to focus on here is our priority options and I've highlighted those in red. That's really where half of the $200 million investment in exploration is going to go this year, those red ones that start in the bottom right-hand corner.

So, the real focus is in East Africa; frontier wildcatting, open another new basis in Kenya, on trend in the rift basins - chain of rift basins that we have there and I'll show you more on that in a moment. And also, the new and exciting basin axis play that we may have in the South Lokichar basin.

I'll show you what I mean by that in a moment. And also, getting after that drill-out of the core E&A there in the South Lokichar basin, where we found 600 million barrels of oil and where we're working to support a development and appraisal activities that are ongoing there.

In the bottom left-hand corner, you see another priority for us there is to get after the Ghana upside. There are field extension opportunities in and around TEN and in around Jubilee.

We won't be drilling any of those this year. It's correct that we focus on the production there.

But we're working that 3D seismic and coming up with some great new prospects and I'll show you some of those currently. So some great field extension opportunities in Ghana.

Now the rest of the options you see on this page in blue, that aren't highlighted in red, have a lower level of activity, but nonetheless, a focused activity and it's mostly seismic interpretation. We have a great seismic asset database and great capability and the prospectors now have time to work through these portfolios and to generate the options and the candidates for the future program.

So this reset actually creates a great opportunity for us to get a lot of value out of these options. I would like now to go through some examples of that activity set.

I'm going to start with Ghana and our focus on high margin oil. We all know the big fields get bigger, it's a common statement in the industry and it's very much a true statement.

And then, at the end of the presentation I'm going to focus on our other priority area which is the East African campaign. So I'll start with this.

What you see on this slide, on the left, is a seismic image of the Enyenra channel. You see the meandering subsurface channel of the Enyenra field and the Ntomme and Tweneboa accumulations on the right side of that seismic image.

On the pies, you see the volumes that we presented to you at the last Capital Markets Day. And there is a lot of upside in those reservoirs and as you see, in those volumes in the pie.

Now watch when I press the button, you're going to see some magic happen, some seismic miracle. If you look at the outer bends on the meanders and you'll see, when I press this button, one of the results from our work with Ikon Science, where we've worked with them to develop this new tool, called [inaudible] which has identified the number of splays, of these reservoir splays which come off the outer bends of the Enyenra channel.

Now this is just one of the tools that we have in our seismic toolbox, very many other ways of imaging the data. But this is allowing us to identify where that upside is.

In the Capital Markets Day we were able to give good guidance as to the magnitude of that upside and what we're able to do now is to put our finger on where it is. So this is a very real, tangible upside.

Moving through some of the frontier exploration options that we have in the portfolio, in the African Atlantic margins as I said, we shift to lower cost plays, shifting to the shallower water, the shelf edge break, where the plays are lower cost to develop. Simpler wells, less complex, better economics.

We've got a vast acreage position of this type of acreage from Mauritania, all the way to Namibia. And each of our positions is now in a proven oil play position.

So these are great assets to have. We've de-risked the basins, we know there is oil here and we're moving to the shelf edge break.

Just to give you a sense of some of the scale, if you look at the map on the left-hand side, I've highlighted, the top of the map, the shelf edge, this dotted line between the greenish area on the right and the yellow license area to the left and the blue ocean to the left. That dotted line, the shelf edge break, is the key and that's what gives us the shallow water and the less complexity.

Now some of these prospects that we've been mapping along the shelf edge break reach sizes up to 400 million barrels. So although they're leads and they're being worked at the moment by our seismic prospectors, we do see some really good materiality in these plays, both in the [inaudible] liquitatious, sediments, carbonates and plastics.

Moving now quickly to the Caribbean-Guyanas Atlantic margin position, again, look at the shelf edge break. You see the dotted line between the blue Atlantic Ocean and the green shelf edge, that dotted line there really marked the boundary between the more complex deepwater environment and the lower cost plays with the simpler wells.

Now, many of these positions were built up in 2013 and 2014, ahead of the industry reset and ahead of - and whilst we were coming to appreciate that these complex wells were an issue. And I would also like to highlight on this slide the large shelf block which is an award pending government approval in French Guyana, update of the Zaedyus oil discovery, where we found 72 meters of oil in the Zaedyus fan.

We think the bulk of that oil is from that system, has migrated up into the shelf, into the shelf edge position. So we've got a vast acreage position in the Caribbean-Guyanas.

We also recently picked up a big acreage southern shelf of Jamaica. With Jamaica and Guyana combined, we've really got a strong position in the greater - in the southern part and the greater Gulf of Mexico area and these are three oil basins.

We've got oil seeps and shows in Jamaica and we've got oil proven in the Guyana basin and in offshore French Guyana. So, really exciting positions.

So there is strong industry interest in the Gulf of Mexico at the moment and we intend to capitalize on that interest. Turning quickly now to Norway and the Atlantic margin there, we have options running in the Barents Sea, where we've made a successful discovery opening the Hoop-Maude Basin with Wisting and the follow up there with Hanssen.

Norwegian Sea, new infrastructure plays. Two wells coming up there, Zumba and Hagar.

Is a cost-effective exploration. We've got access to infrastructure and good deal flow, good line of sight through to commercialization.

And then finally here, the North Sea APA 2014 awards. We gained a great position, on the shoulders of the giant Johan Sverdrup field.

You see a seismic section here in the right, the Johan Sverdrup joint venture on the left of the seismic section, the new Tullow Oil joint venture. We think we're in the oil migration fairway from the basin, the Ketch in through to the Johan Sverdrup oil field.

So a very exciting set of prospects in that new acreage position for us there. Now, finally, the upside in Kenya, here we have some exciting basin testing wildcats and a new play tester.

Now, let me explain this. You've got three maps here, they're all at the same scale.

The map in the center is one you're probably most familiar with, the South Lokichar Basin. The map on the left is up in the north west corner of the acreage, near the Ethiopian border, the West Turkana Basin and there, we're currently drilling the Engomo-1 well.

We expect to have a result from that well at the end of the month, the beginning of next month. And then, on the right-hand side you see the southernmost part of the license area, where we have another basin, the Kerio Valley Basin.

Now this slide shows three basins. As you recall, we have about a dozen basins in the whole portfolio in East Africa, so this is just a subset of that, but this is the near-term activity.

Let's look quickly at the central map because there is a new play there that I want to introduce to you and it's something we're working on. You see the light green blob, if you like, in the middle of the basin, it occupies a large part of the South Lokichar Basin.

And then, if you refer to this cross section beneath it, you'll see that, looking at the cross section, the exploration activity has mostly been along the basin bounding fault and the string of pearls on the west side of the Rift Basin. We've also had drilling activity on the far right-hand side, on the eastern side, the flank of the basin, where we've made discoveries at Etuko and Ewoi and other places.

And what we're realizing from the new 3D seismic that we've acquired, the regional 2D seismic and some of the well results, is we think we may have a basin axial play, where the sediment isn't coming in from left and right but is coming in from north and south, along the axis of the basin. So we're going to try and tag the edges of that with the ongoing appraisal activity in Ngamia-7 and Ekales-2 and we'll have the results of those during the year.

And we get some more encouragement from those then there is a candidate here to drill in the center of the basin and try and pick up the basin axis play. But this could really be quite a game changer, a very exciting upside potential.

With that, I will hand the floor back over to Aidan for a conclusion.

Just to finish off, my view is that this may have bottomed out. I could be wrong, but we have taken all the steps that we needed to take.

We've probably taken more than we needed, just in case there is further volatility downwards. And I think what we tried to show you is that we've a very good asset base and it's well funded.

So, we're pretty confident, thus going forward. Now I'll open up to questions.

Just, first of all, before we go to questions, I'm sure there are an awful lot of questions in the room, but as is usual practice in Tullow presentations, can I ask that you resist asking multiple questions? Could we have one question per person?

Hopefully, that will give the opportunity to everyone who has a question to be able to ask their question. And if you have any questions after that, you can certainly come back to ask further questions.

It's Dan Ekstein, UBS. You've written off today the best part of $3 billion of capital which I think highlights risks around capital allocation in this sector.

The $5 per barrel finding cost that you've previously targeted is one that a number of us have struggled in previous presentations to see as that differentiated. And Aidan, you've talked at length about how you see the U.S.

shale industry as having fundamentally changed the future shape of the industry, so that's a bit of a context to my question. As a shareholder today, I'm looking forward to the cash flow uplift from TEN.

And my question is specifically around if you could help more closely define the reinvestment criteria around those cash flows from TEN in terms of a new finding cost or a hurdle rate on investments? Thanks.

I think the shale industry as I said before, did fundamentally change the industry, in a number of ways. I went to a presentation last year on the shale industry which was up in Scotland and it was very obvious that the U.S.

shale industry worked in a completely different way than the international oil industry, the way that they had used innovations to cut costs, their drilling. And they had a very, very good cost structure at the well head.

I'm not sure about the cost structure corporately, but at their well head and what I was saying before is that we needed to take some learnings from that and bring them into the traditional oil industry. And we looked at areas within our own portfolio where we could use those learnings and for example, East Africa's a classic example.

And I think some of the stuff that has been going on in the shale industry, you now see those savings come into place like Rift Valley. And in fact, actually Cairn India have made huge savings in the drilling cost in East Africa.

So, there are a lot of movements in cost cutting. The industry over the last four or five years and I've said it before, if you go back five years, when we found Jubilee which is more than five years ago now, an offshore well, 100 million barrel oil field offshore was commercial.

Today or just before this whole reset, you would have needed 300 million to 500 million barrel oilfield offshore to be commercial. And it was an awful lot harder to find a 300 million barrel, 400 million barrel oilfield than a 100 million barrel oilfield.

And that's why last year we started looking at deepwater and said, well, there's no percentage point in investing in deepwater, it just doesn't make sense. Let's move in and look at finding smaller fields and nearer to shore or on the onshore.

I think what's happened in the last six months - this has happened before. This is not the first time the industry has reset itself.

What you will see is a dramatic cut initially in costs, the drilling costs, you'll see a cut in service costs, you'll see a cut in the company's overheads as we're all doing. But more importantly, you need to see a cut in the taxation.

You need to see a cut in government's take. And that's gone up quite dramatically over the last five or six years.

What you do is you reset the business, you cut your costs down, you make it profitable at these levels, you look at the existing assets and look at how you can get upside around data assets and be the first company that's ready for any uplift. When we're looking at - Angus talked about it there in relation to exploration, we're out looking at exploration areas and plays that work at $50 oil.

And that's what you have to do. If the oil price increases great, you make more money, but the business has to work at $50 oil.

And there is going to be - the key focus for any business right now is to get the business absolutely right. You can't assume the oil price is going to rise and save you.

The companies who make the decisions fastest and first generally come out the best. And we will - we have all the hard decisions taken.

We will be cutting further costs, we will be cutting overhead costs. By mid this year we will be a much more streamlined business.

We'll have a comfort factor in our funding. And we look at opportunities.

Oil prices, if you look at the finding costs of oil, the best place to find oil right now is around existing fields and in places like East Africa. And part of getting those costs down, built into the finding costs is our own costs, Tullow's own costs.

It's not just the drilling costs. So all of those costs have to be cut.

Alex Topouzoglou, Exane BNP Paribas. Obviously, a lot of talk about cost cutting, but what about maximizing revenue?

So have you had discussions with the Ghana authorities in order for them to allow flaring in 2015 in order to ramp up to capacity before the end of the year? Thanks.

Yes, I think the focus is absolutely on revenue. One of the points I was trying to make was about timing of capital investment is critical at the moment, whereas in a much higher oil price you would need a bit slacker, about saying we'll put the wells in place and make sure there's plenty of excess capacity.

I think at the moment you're trying to fine-tune that. So I think the focus is on maximizing revenue to reducing OpEx and moving around the capital.

I think with respect to flaring, I think we have to recognize is within Ghana. I would almost argue, there is more focus on gas within Ghana than there is on oil.

If you look at the press over the last 12 months, 18 months, there has been more focus on the delays in that gas plant. And the reason for that is because of the delays in the gas plant and therefore, the lack of gas supply from either there or the West African gas pipeline, there's been power cuts across all of Accra and Takoradi and many other places in Ghana.

So I don't know that we would even - there is an environmental aspect about flaring that take it into account, but there is also a kind of sociopolitical aspect around flaring. So you've got to look at it on a longer term, rather than just we do anything for short-term revenue.

We don't do anything for short - we focus on short-term revenue and we move the things that we think are appropriate to move. But kind of starting to just burn gas which actually is Ghana's gas, even they are much more focused on, yes we do need the revenue, but actually it's better to look on a slightly longer term than just the six months.

It's Theepan from Nomura. Just coming back to the present, you talked about resetting the business, particularly oil so I just want to talk about the RBL, just the timing of that redetermination.

Is there an assumption that the RBL is reduced? And could you just walk through - I think you talked about $70 potentially coming down for the banks to $60, but the resource base being, let's say, valuated differently on Jubilee, 1.25P as a ratio between 1P and 2P.

Where do you think that number goes? Thank you.

So on the RBL part, can I just ask the first part of your question again, I'm sorry?

I was just wondering, you're talking about the reset to $50. In the context, is there some sort of assumption that your RBL is shrunk or not?

And just walk us through timing and that value utilization--

First of all on the amortization, the amortization begins to kick in after TEN first production, in the back end of 2016, I think in October 2016. History will show that what we normally tend to do is to actually either extend to defer that amortization or refinance our RBL before such amortization happens.

I think amortization is saying that we will deal with well ahead of time anyway. So point one.

Point two is the bank price index around about $70 per barrel previously, so if you're looking at our past redetermination back in September, October last year it was about $70. Indications are that there will probably be probably in the mid-60s rather than $60 this time round.

To the extent that we lose some capacity on the RBL pricing, already we were in a position where we did actually have some excess capacity anyway, but versus our $3.5 billion commitment, that will take us down a bit below that $3.5 billion. But equally, now we've got four years production experience on Jubilee as I said before, we're effectively at a kind of 1P, rather than a 2P which is where you're probably hoping to get to after four years or so, we're still at 1.25P and part of the conversation in March is getting ourselves further up towards 2P.

So when you take all that into account, it kind of broadly cancels out.

And just to reconfirm your 2P number that you're carrying, please?

On Jubilee, it's about 500 gross, roughly.

Brendan Warn, BMO Capital Markets. I guess my main question relates to Jubilee and that you look to have had good efficiency and uptime in 2014.

Just considering a bulk of the cash flows flow through the turret, what contingency have you got in place this year for the maintenance for spares and any sort of outages in terms of keeping the efficiency high. Secondly, in terms of the TEN development, what sort of float or capacity do you have in your schedule for on-time delivery?

Yes, we had a particularly good uptime in 2014. We had a number of planned events.

I think the team there have got much better at having planned events. So we've had minor shutdowns within Jubilee, even within the seeding the 102,000 within there, we had planned shutdown events.

And really, taking specific very short shutdowns for particular items is a better way to run your business than having unplanned events and then reacting to them. So the team over the years have got better and I think 2014 was one of the best years to-date in that.

And I think as we look at 2015, it's exactly the same. We look across the system which is the FPSO, we identify certain items which we feel like we'll need to work on.

We're still questioning the need for a shutdown. We often have an annual major shutdown, currently, that's planned for early 2016.

We don't see the need to take one in 2015, but we do have small planned events. So it's really continuing to get much better at planning is that's what leads to the efficiency within the FPSO uptime.

And in fact, in the unplanned events, things happening because of shutdown, there was very few of them. I think it was about 2% or something which is actually pretty good for an FPSO of that complexity.

With regard to TEN and - we have financial contingency within our budget. So we've got a headline of $4.9 billion and we do have financial contingency in different categories.

And if we look at where we're today on the financial contingency, we feel we're reasonably comfortable. We've used some of it as you'd expect, but we actually still have the right level of contingency left, given where we're in the project.

As I was saying on timing contingency, all the wells, the first part of the wells is behind us, so we don't need contingency on that, it's done. We have time contingency on the completions, so that's built in.

We assume that one completion will go wrong, we hope it doesn't, but we plan that in to make sure we still can all the wells ready for first oil. On the FPSOs, I was trying to highlight we planned to have three dry dock sessions.

We had one long one. So actually, rather than a contingency decrease we've actually increased it with that dry dock.

So we've got excess contingency which I think just gives us a much better chance of that vessel flowing - leaving away from Singapore, but importantly with no punch list. That was one of the big successes of Jubilee.

A lot of people meet their sail-away date. Maybe what they don't tell you is actually there's thousands and hundreds of thousands of man hours still to be done and if you do that in Ghana, it'll cost you three times per unit cost.

I feel like the FPSO - and if we look at all the component parts, the guys are continually juggling. Something maybe runs, it starts to lose a bit of its contingency, they're right on it.

And really, I think we feel pretty good that we're preserving contingency. It's not to say we won't use it up once the really complex piece starts which is in the third, fourth quarter where you're actually trying to do all the install.

But I would say where we sit at the moment it's better than good on the TEN project. You just want to be cautious about - there is a lot of complexity ahead of us, but we're feeling pretty good about where we're.

[Inaudible]. Just a quick one for Ian on the RBL.

To what extent, if any, does the oil price volatility impact the contract used to re-determine the RBL?

I think the factors that are used, the oil price is a sort of independent amount which is - independent number which the banks will use. So the discount rate is separate to the oil price, it's just there's different elements that go into the RBL.

The banks will take a view, but I think the banks have a view which says let's be sensible about what we think our price going forward for the RBL actually is. And the way the RBL generally calculates numbers in there is a very conservative basis.

There is quite a lot of, if you like headroom and ability, if you like for the banks to be sensible about what they think the price deck is and the discount rate, etcetera, but they're too independent.

Caren Crowley, Davy. Just a quick question on Jubilee.

If I'm not mistaken, your numbers imply that you'll spend $400 million on CapEx in Jubilee this year. I'm just wondering where that investment is going.

Is that the complete Phase 1A? And 2016, how should we think about sustaining CapEx for Jubilee?

Thanks.

Yes in this year, if you look at the buildup, it's about $300 million in Jubilee, it's about $1 billion on TEN and $300,000 on Jubilee and you're right, that's allocated. We've got a number of ongoing Brownfield modifications to the FPSO that we're always looking to increase capacity and modify.

So there is a little bit of money allocated towards that. And then, the other allocation is towards a couple of well completions and adding how we budget, I think, to a couple of wells in there for 2015.

Again, it's that capital - we've allocated all the capital we think we'll need, so again we're looking at capital on these areas as top end. And if we can find - field performances better than we expect and we're able to, then you'll see us sliding some of the activities forward, so looking to kind of manage the capital down.

But we have allocated it within the $1.9 billion.

It's Rafal Gutaj from Bank of America Merrill Lynch. Just two questions, well one question on Kenya.

How many more wells do you need to drill before you FID that project? And what is the minimum oil price you'll need to sanction that project at the current or anticipated size without having to shift FID dates to the right?

In terms of the appraisal, it's kind of single-digits in terms of the number of wells. A bit of it is depending on the outcomes of the appraisal wells.

The good thing with the onshore rigs, it's pretty flexible. We can shut them down when we need to shut them down.

We only need to commit to the next well. So we're almost at the end of the appraisal program and depending what we get, we're drilling Ngamia-7 and Ekales-2.

Actually, if they come in very positively it might lead to more appraisal, if we feel that we can further extend. I know Ngamia-7 is a kind of bold out step appraisal well.

If that was to come in, we may sit back and see, actually, that's shown us some significant upside, so let's go and appraise further. So it's variable is the answer, but it's not 10s of wells, it's single-digit wells.

The EWTs are probably the more important in the short term. There is no single break-even price.

As I said in the presentation, what we've seen in Uganda was a significant reduction. We had time available and we used that time to devalue engineering and we saw a significant reduction in the capital cost which obviously has a major impact on what is your break-even.

And then in Kenya, it's too early to be trying to contemplate that at the moment because we feel we've done an initial design and now we're actually trying to imply all the break-even - sorry, all the value engineering from Uganda. There is a lot of lessons to be - that are being transferred across the Kenya about the design and how to optimize the design.

And then as we look at the pipeline, there is quite a bit of moving parts there, both on the design of the pipe - we've got a basic design. We've done all the pre-FEED for the pipeline.

We know it's technically viable. We've got time now, so time can be best used by continually optimizing the pipeline cost and that's then impact by the design in the routing.

And there is quite a bit of movement around there, we think downwardly that we can achieve and so you package all that together. But as I said, if you look at Uganda, it's about $6 per barrel capital development cost.

Operating costs in these environments are relatively low compared to our deepwater offshore-type development. They're pretty robust to pretty low oil prices.

Again, there is a whole opportunity to sit down with government and have that conversation about making sure it's attractive enough. In Uganda, we've got some big partners who've got probably quite a long list of projects and they've been talking heavily about capital allocation, so that's a real opportunity to be discussing with the government.

We've got to get this project - it's not just about it breaking even, we've actually got to get it to the top of the capital allocation list in some of our partners' portfolios to make sure that attracts the capital. That's an opportunity actually around the problem.

It's Sanjeev Bahl at Numis. I just had one question with regard to the liquidity risk, management again concern statement.

It mentions that it could become technically non-compliant with one of its financial covenant ratios in the first half of 2016. I take it that's the 3.5 times net debt-to-tax covenants, but just wanted to understand under which scenario you envisage that potentially happening.

You're quite right, it is the net debt-to-EBITDA covenant. If current market conditions persist and technically we could maybe get to that point and this is really just - but it is way into 2016, just before TEN first oil comes onstream.

Really, we're always very transparent with our disclosures and that's what we said. But the reality is that as I tried to say earlier, really it's all about funding and liquidity and we're liquid through that period of time and beyond.

And really, a covenant breach really is just a control of the banks to actually say, hey, let's have a conversation because you're getting above that number. And we expect to have that conversation in the coming weeks and already we're going to start such conversations because we always plan well ahead, just in case something might happen in one year or 18 months' time.

So we don't see that's issue, it's just in the interests of full disclosure.

It's Michael Alsford from Citi. Just a question on Kenya and Uganda.

I think back before TEN was sanctioned, you were pretty committed to sanctioning TEN at the current equity levels that you had then, regardless of the farm-down. Could you maybe talk on East Africa and how you see Kenya and Uganda?

Will you sanction, if you do get to sanction in late 2016, regardless of a farm-down? Or would you need a farm-down before you would actually push the button on that development?

I think the focus at the moment is getting the project ready to have the option to sanction, so that's our total focus. What we do with respect to equities, we've got a lot of time to decide that and there is a lot of factors that will determine whether we want to fund it fully ourselves, we want to farm-down a bit and in what shape or form.

I think our view is a bit like TEN. When we ran up towards TEN, our view is very much we were going to position ourselves to sanction TEN and be ready for sanction TEN because that's the creation of value, actually getting it sanctioned and getting the project underway.

And we'll be able to do that at full equity. That's the conversation we had as we ran up towards the sanction.

Now we had a preference to then dilute, but our view was we've got to be in a position to run through the full equity. As I say, we looked at the dilution of the reduction of equity, talked a lot about why that's now not the appropriate thing, so we're back on the plan that we started at the point of sanction.

And I guess as we head up towards end of 2016 or whenever it is and decide take our option to sanction the East Africa project will be in the same thing. We'll be looking to make sure we're in a position to finance our equities and then, if there's a better option in terms of value creation then you would take it.

So the answer is anything's really possible. I think the focus now is create the value by getting the project ready as a very commercially viable, focus on reducing the costs, maximize the resource, making it as attractive a project as possible and we've got good partners.

They've got a lot of competition for capital, that's great because that's helping everyone focus their mind.

David Mirzai at SocGen. You've talked about the fiscal terms for exploration licenses may haven't come down.

You've also talked about entering negotiations with governments on fiscal terms, sort of fiscal basis for new developments. But I suppose I'm more interested about your existing host governments with production.

Gabon seems to be a case in point. You have a country there, the oil price is halved.

Obviously, their revenues were down. They're trying to set up a national oil company to try and get more control over their own industry.

And then, we're getting an interim environment of cost cutting both on an operating level, so a local level and also at investment levels. Where do you - you obviously work for a number of African countries, how are those talks going with governments where you already have production?

What would they really like to see out of you? And how is this cut back in investments affecting them?

Thanks.

Well it is affecting all the countries. Quite a few of the countries that we're in, they're net importers of oil anyway, so the actual low oil price suites them.

Like Garner for example, imports more oil than it produces. I think what - there's two things, is their revenue, the tax revenue has decreased quite a lot from the oil sales and there - we will help that by reducing our cost.

But we're not asking the governments to reduce their tax, if that's what you're saying.

[Microphone Inaccessible].

Yes, I think like as Paul was saying, we're striving - the ones that we operate in Ghana, we're looking at reducing the operating costs and when TEN comes onstream, for example, in Ghana, we'll be spreading the Ghana overheads over a lot bigger production asset, so that will reduce their costs. The non-operated areas, we do know that the operating partners like we don't operate in Gabon are actively looking at reducing costs.

One area in Ghana that we've been talking to the minister about is local content is a big part of our long term relationship in Ghana and we've been doing a great job of it. Well actually, if we can take some of our non-core activities in our supply chain and push it a little bit more of it out of Tullow and into the local supply chain actually that's likely to reduce costs.

So there are areas like that, that we're just putting a lot more effort and focus in to try and accelerate them and actually, so that's good for us because our costs come down. It's actually seen very well within Ghana because actual local content is going up.

So in the environment you're in, in Ghana is about sitting down with the minister and working out we both want to reduce the costs because that - somebody says - or everyone's about maximizing revenue. There is some really smart ways in which you can try and do it.

It's Tom Robinson at Deutsche. My question relates to hedging.

Could you share your thoughts on how you're thinking about hedging in 2016, 2017? What I'm thinking about is are you actively rolling forward those positions today and potentially locking in a what could ultimately be a lower price on a higher proportion of your production or are you letting those positions unwind and taking more a spot view of the market?

Thank you.

Our hedging strategy is pretty simple, actually in the way we do it because we don't claim or think we have the capability, it would be great, speculators on the oil price. What we tend to do is simply hedge to reduce volatility and to understand and underpin our cash flow.

What we tend to do basically is to hedge on a ratable basis. So we perhaps do a couple of hedging transactions a month maybe, 500 barrels per day of production, that sort of thing and basically just build that over time.

If you remember that chart I showed you, you see the hedging protection we have at the moment. The dollar per barrel is certainly at the moment higher in 2015 than it is in 2017, for example.

But whilst you always like to try and put a bit more in when the oil price is are a bit higher and perhaps a little bit less when it's a little bit lower, but our view is to do that on a rolling basis, little and often and build the protection in that way rather than take big positions which is not really our role as an independent oil and gas producer to actually take big provisions. So, it's kind of steady as she goes.

It's James Hosie from Barclays. I'm just trying to understand or better understand the relative magnitude of this $500 million target for cost savings.

What proportion of your 2015 CapEx budget and operating cost guidance relates to the costs you describe as indirect?

I would say that we probably in a given year, we would probably allocate about $350 million to $400 million to CapEx from internal costs, if that helps answer your question.

Yes. And in terms of operating costs?

Probably about $150 million, that sort of order.

Thomas Adolff from Credit Suisse. Just a quick question on base, but before I get to that, U.S.

shale was about 4 million barrels per day, global supplies about 92 million barrels per day and decline rates are 3% to 5% after heavy spend and at some point demand will normalize. So I think in the context of that, your project in Kenya is pretty good.

The question on base and for my question I want to include Ghana as base, so both Jubilee and TEN because at some point it will come into production and I look at the upside resource base which is quite significant for both fields, how should I think about the duration of plateau? How should I think about debottlenecking upside on Jubilee?

How actively are you chasing that? And how should I think about TEN and the opportunity there as well?

Thank you.

Yes, so I think within Jubilee as I said, we've got pretty clear milestone this year by the end of the year to be able to pushing the capacity of the FPSO which we guided before is somewhere around 120,000 to 125,000. We're actively - some of the capital that has been allocated into Jubilee as we talked earlier, is actually about continual debottlenecking as we identify areas that we could put excess capacity or redundancy which is it would mean that it's another bottleneck removed or it can increase efficiency, so rather than taking something down for maintenance you actually can take that unit down and switch on another one.

I think with Jubilee it's about getting up to the 120,000 plus and then looking at the economics of further investment to accelerate plateau. I think if we were to look at the resource base we have on Jubilee and the infill well potential we have on Jubilee.

I don't think there is any reason why we couldn't be pushing Jubilee plateau out towards maybe end of the decade around 2020. And then you're into a continual optimization point of view, depending on oil price and acceleration about do how much money do you spend to accelerate that oil because that's what you do now, you're generally not creating new oil, you are actually accelerating.

So that's the way I'd think about Jubilee as a kind of plateau out to 120,000, we've guided on the resource base and then really the opportunity is acceleration of revenue through acceleration of production. And then, on TEN, we've guided some profiles on TEN.

The thing on TEN is let's get the field onstream. We've shown the guidance in terms of resource numbers of the upside resource we see on TEN in terms of oil.

We do see and Angus has highlighted, some of the what is going on in the background which is very timely because as you bring the field onstream, you already want teams of people to be then following on from the work Angus one in thinking about infill and reservoir modeling to create infill opportunities. And we shot a big 4D seismic survey.

We've learned a lot from EG, Equatorial Guinea, the Ceiba and Okume fields. We're just continually infilling those fields and maintaining production which is great, great investment, even at low oil prices and that's where the 4D seismic will get Jubilee and TEN to, maybe, in five years to 10 years.

So very long life, stable asset with lots of opportunity. I think maybe one thing I haven't mentioned is really the gas resources around the TEN area.

As you're aware, we've got some non-associated gas being produced with TEN. The gas pricing that we were in discussions with wasn't really attractive enough for us to invest further with the sanction of the Sankofa development.

And as we understand it, quite attractive gas pricing associated with that which has made it economic as a gas and non-associated gas development, that creates a whole set of new opportunities for us around TEN. There is significant gas resources around TEN which we retain and we can then subsequently develop as a kind of extension of TEN.

So there's a lot to play for. As Angus says, there is a whole game out there beyond plateau of TEN and Jubilee.

And it's kind of taken - if you think about the 200,000 barrels per day, in 2017 we'll be at 200,000 barrels per day and the questions we'll be asking ourself is how far can we push that, both in the terms of oil and gas production as well?

[Microphone Inaccessible].

I think what we would like to do is include, MTA was the question. What we consider is the, MTA, we would like to really see that as just part of greater Jubilee.

Why drill MTA in preference to Jubilee infill well, if Jubilee infill well is a better use of the capacity? We're in discussions with Kosmos, the operator of MTA about finding a solution which really just brings MTA together with Jubilee and then you just have a long list of infill opportunities which extend plateau and look at accelerating the plateau as well.

Alessandro Pozzi from GMP. I believe Aidan, you mentioned that the industry now has to reset to an oil price of $50 per barrel.

I was wondering, is this now the key criteria for project sanction, for Tullow to sanction new projects going forward in Ghana and MTA? But also, in Kenya and Uganda, I believe the FID there has been postponed to the end of 2016.

Is that why? Is it the reason why you're waiting for costs to come down?

I think the industry as I said before, it's been through these things loads of times, this is not the first time. Very few people will sanction projects today, at any price, there is too much uncertainty and I think when it stabilizers and the industry feels comfortable it's stabilized then you start sanctioning projects.

If we were to look at going to our Board today for a project sanction, it would be below $50.

I think maybe if I could just add one initial comment on that in terms of the relationship between the oil price and the sanction of East Africa. Actually, the reason we see the sanction likely being out at the end of 2016 is more to do with the government now - the two governments have now got together.

They've appointed a technical advisor and they've set out a process to try and look at optimizing the route of the pipeline and working with the JV partners. And when we look at that process, the reality is that process is going to probably lead to a sequence of events that mean that the sanction is going to be out towards the end of 2015 - sorry, into 2016.

I wouldn't correlate the oil price, it's actually more the reality of the process the governments are going through with respect to the oil pipeline. So in one hand it's good, but it's likely to lead to a later sanction.

[Microphone Inaccessible].

We've always guided about three years after sanction, roughly.

So that we can finish on time, if we can take one more question in the room and then we'll go to the conference call.

Dragan Trajkov from Oriel Securities. Actually, a cash flow question.

The cash taxes this year seems to be fairly low, in the $30 million range. What is that a function of?

How should we look at that in 2015?

The cash tax is low because of the low profits and the Norwegian rebates, etcetera . 2015 will be a more normal year as we would expect the cash tax to be more like normal levels in 2015.

But because of both the combination of the losses and Norwegian rebate then the cash tax is a low in 2014 and obviously, there is some sort of timing effect there as well. So, all back to normal in 2015.

Okay, there will be time at the end to, perhaps have a one-on-one questions with the execs. But for now, if perhaps, we could go to the conference call to see if there are any questions on the line.

I just had a question again on the balance sheet. The decommissioning liability rose pretty significantly, I think by about 40% from the end of 2013.

I think that's despite the sell down of part of the Schooner and Ketch. Just wondering if you could talk through the dynamics of that and also, just how some of the banks look at that and kind of think about that.

Thank you.

Yes, that adjustment is, probably there is two main inputs to it. Whilst in the very short term people's view would be, well, contracting costs are coming down why wouldn't you decommissioning?

Again, the decommissioning estimates we put together are more looking at five year to longer cost cycles, so you don't have those oscillations. But in terms of the increase, we just completed a fairly major review of all of our assets and assessments of our operators' estimates.

And so that work has - a significant piece of work was done this year and so the new estimate reflects that new piece of work done. And also we're in the midst of the TEN's decommissioning which is a real ongoing project which is starting to show out some costs and some increases associated with that.

So it's probably the two factors, the fact that we've got a live decommissioning project - not ongoing, but be executed probably in the next 18 months, but the engineering work's getting done and a major review of our decommissioning liabilities.

Just on Ghana and specifically the issues surrounding onshore gas processing which admittedly have been pretty much outside your control, how confident are you that those issues won't re-emerge when TEN comes onstream? And what mitigating factors can you put in place to ensure that you can get up to full plateau production fairly soon?

It's quite difficult to hear, Gerry. I understood the question to be around gas handling.

The main issue with Jubilee wasn't the facility offshore, it was the absence of a gas plan onshore, if I understood the question properly, that was the bottleneck. So we had a plan where we were going to inject about 30% of the gas and export about 70% of the gas onshore and that was what was negotiated with the government and the FID, the field development plan.

As it happened, we ended up having to inject 100% of the gas for an extended period and that's what led to the bottleneck offshore. It wasn't the actual facility.

If we look at TEN, we've actually put additional processing capacity with on TEN. So there are some lessons learned there just about the processing.

The plan on TEN is to inject all the available gas for the first year or so because we need the gas as part of the reservoir management. And we don't want to export gas onshore until a year after start up and we do have an operating gas plan to export it to.

In summary we don't see, for those reasons, gas handling being an issue on TEN.

Okay, thank you very much for everybody attending. If you have any further questions, obviously, feel free to grab the exec at the end.

Obviously, James and I are also available and you all know how to get hold of us. So, thank you very much.