Tullow Oil plc

Aidan Heavey - CEO Les Wood - Interim CFO Paul McDade - COO Angus McCoss - Exploration Director

Dragan Trajkov - Stifel Brendan Warn - BMO Capital Markets Mark Wilson - Jefferies James Thompson - JPMorgan Al Stanton - RBC Rafal Gutaj - Merrill Lynch Michael Alsford - Citi Stephane Foucaud - GMP FirstEnergy Colin Smith - Panmure Gordon David Mirzai - Deutsche Bank Anish Kapadia - Tudor Pickering, Holt

Okay. Good morning and welcome to the 2016 Full Year Results.

And as you may know, Ian Springett is on sick-leave. And I want to thank you all for who sent - those who sent well-wishes to him, he’s doing incredibly well.

He’s back at home recuperating. And Les Wood has stepped up Interim CFO and he’ll take the presentation today.

And I think we’ve come out of two very tough years and shall see in the results and Les will present some of that numbers. But I think what we’ve managed to achieve cost wise in resetting the business over the last two years, has put us in a very, very good stat.

And that discipline in cost control will be obviously embedded in the business now going forward. Development-leveraging is on the way since the last quarter of 2016.

We started generating free cash flow. With 10 completed and Uganda farmed out, we’re now starting to pay down our debt.

And I think with the rise in production profile that we have in the business, lower CapEx and further portfolio adjustments we have a large number of options in which we can accelerate that de-leveraging. We’ve taken quite a number of steps to improve our portfolio we’ve taken out a lot of assets that we felt were unsuitable for the company going forward.

They have been sold or let go. And that has helped as well to make sure that the teams that we have are focused really on assets that can deliver very good value going forward.

The target of all that was really to create a solid base for the business and I think we’ve achieved that. The development of our previous exploration is in TEN & Jubilee have now left us with a very, very good, solid low-cost high-margin cash flow.

And that will help us to de-leverage the business and grow. And also to far-most of Uganda and the exploration successes we’re having in Kenya, it really gives us a clear path to enhanced cash flow and profitability in the future.

I think the teams have done incredibly well. All their main targets and main things that we set ourselves for in 2015 and ‘16 we have achieved.

I think they’ve done incredibly well. The portfolio that we’ve left with now I think is a very, very good portfolio.

And it’s a portfolio that I think we can start to deliver significant value. One of the key areas for growth in the business and we believe in the E&P business is exploration, and exploration is really where you can get transformational value growth in the business.

And I think Angus and the team; have done a fantastic job over the last few years in revamping the portfolio of exploration licenses. And we know have as Angus will show you a very, very good portfolio of licenses that work in this current environment and that can deliver we hope significant value for our shareholders.

And Paul will be going through the production. We have a very, very strong cash flow going forward.

And as I said, a very clear line of sight to enhancing that cash flow through East Africa over the next decade or so. And I think as overall, what we have achieved over the last few years is a very balanced company and it’s in a very, very good position to move forward and take advantage of any opportunities that we’re sure will occur in this current climate.

I think the industry has changed quite a lot. And we have to change with it, and I think we’ve achieved those changes.

I’ll hand you over to Les, who’ll take you through the numbers.

Thanks Aidan, good morning ladies and gentlemen. I just want to say a little bit about financing and what’s going on in the last year.

2016 was as Aidan said, on the back of a difficult 2015, another difficult year for our industry. In January you might remember Brent oil price reached a low of $27 per barrel and why that did increase somewhat was $56 by the year end.

However, despite this difficult environment, as a company, we insulate ourselves well by a number of features, the self-help actions that we’ve taken over the last two years, the stability provided by our prudent hedging program and new productions from TEN. Discipline has been the key, not only in implementing CapEx and OpEx reductions but also in the case of G&A.

And you will have seen the over, the sales target back in 2015 of delivering $500 million cost savings through G&A, we’ve already to this point delivered $300 million and we’re well on our way to deliver $600 million or in excess over the three-year target. And all this is being delivered through a major simplification project which we executed well over the last 12 to 18 months.

Overall, our underlying cost across the business, are in good shape. Operating cost, are down 5% year-on-year and CapEx down 20%, with 50% year-on-year.

We will continue to see focus this year with CapEx of around $500 million before we will refund the cost from the Uganda transaction. One of the key things and one of the issues with our industry is that we plan to stay lean and disciplined even as the oil prices.

So this will be a key focus area for us. The farm-down in Uganda, the veining of the geo demonstrates the commercial potential of our portfolio that removes major CapEx from our forward plans and guarantees a healthy increase in production at the start of the next decade.

We took decisive actions to preserve liquidity including exercise the RBL Accordion, RCF extension and diversifying our capital structure through the issue of a convertible bond. You will also have seen that we just announced yesterday or today that we’ve executed first financing initiative of 2017 by standing us here for a further year to April 2019.

So, what’s just reflecting that all our participating banks supported, it was oversubscribed. It was done in a very quick period and that’s on the same time as conditions.

So I think all of this bodes well as we go into refinance of the RBL later this year. And all of these actions are underpinned by the continuing strong support from all of our banks.

So, thanks for productive financial management including our insurances, which have covered the Tada issue in Jubilee. We find ourselves in a strong position today.

Effectively we have rather just storming in our sector, left 2016 generating free cash following the start-up of the TEN project and began process of de-leveraging. All of which puts us in a stronger position as we said - as I said, as we look forward to refinancing out there in 2017.

Now, here is a quick summary of the numbers. Here is the P&L and some other key data.

I’ll just draw a few points. The first being in-line with what I’ve just said on costs.

If you can see our admin expenses were down by 40%, all part of our self-help activities. I would also point out our loss after tax of $600 million and the magnitude of the losses driven by a few significant non-cash items, one being around the deals that we’ve done this year on Uganda and Norway.

And also the goodwill impairment associated with the Norway transaction. And then second, PP&E impairment driven by the low oil prices over the course of 2016.

On a more positive note, as you can see in our other key data, we delivered approximately $100 million of operating cash flow despite the low oil prices. And this was underpinned by our strong hedging program.

I’ll cover capital and net debt later. Here is just a short summary of CapEx.

No great surprises on this slide. As we promised post TEN-execution our committed CapEx was reduced substantially.

And as you will see from the picture, it has dropped by 50% year-on-year. And we also came in 20% lower than forecast showing that discipline that I mentioned earlier.

2017 forecast is $500 million but we do expect this to be last as a result of the Uganda CapEx being recovered through the transaction that we just did with Total. We’ve targeted our capital allocation to suit both the balance sheet and market conditions.

Angus will talk a little bit later about what we see happening with respect to well activity. But you can see in the case of offshore well activity, we’re two to three times less given current oil prices on a cost basis in that activity.

So we’re able to actually stretch the money a lot further as a result. We have no specific forecast yet for 2018 though I can see us spending more money on high-impact exploration in West Africa but only as and when budgets allow.

And I have mentioned hedging as being an important part of our finance strategy and has been for the last 10 years. If you look at 2016 specifically it delivered $363 million of revenue and between ‘16 and 2015, a total of $728 million.

With the recent recovery in oil price, the mark-to-market of course is less but we continue to hedge to protect the downside a volatile oil price environment. In 2017 we have about 60% of our oil entitlement volumes already hedged at $60 per barrel.

And if you take account of the loss production in Jubilee associated with the shutdown which is covered by RBI, business interruption insurance with effectively has 80% at $60 per barrel. We expect and will continue to progress our hedging program as it’s very clearly shown as worst over the last two years.

And just to say something about our balance sheet debt on liquidity. As I’ve mentioned little bit already, we’ve worked hard in 2016 on balance sheet as laid out on this slide.

We took decisive actions on RBL and RCF facilities including routine terminations, covenant amendments, RBL commitment cancelation and RCF extension. As I said, these are all testimony to the strong relationships we have with our banking syndicate.

We also diversified our capital structure through the issue of the convertible bond. Along with self-help these actions have left us with $1 billion of liquidity as we exited 2016.

As is mentioned on the slide, we’ll all be looking for less headroom going forward. We prefer the cushion of about $1 billion during a period of high committed CapEx as we were doing with TEN, project that we believe that our level of about $500 million will be more appropriate going forward.

In addition, it’s also worth saying that as we complete the transaction in Uganda later this year, we expect the $300 million positive cash impact as a result of the refund in CapEx and also the completion bonus of $100 million. All of our actions be it, self-help, the Jubilee TRP, the execution of the projects itself plus the insurance, the start-up of the TEN project on-time and on-budget, completing the Uganda farm-down and the commencement of organic de-leveraging, all stand us in gusted as we go into refinancing in the first half of this year.

So, in summary, despite a difficult external environment, we’ve achieved a lot as a company. We’ve achieved significant cost savings across CapEx, OpEx and G&A.

And very importantly we’ve instilled cost discipline in the company. We’ve already started generating positive free cash and delivering major portfolio management with further options available.

And we’ve left the year with $1 billion worth of liquidity headroom from our actions taken throughout 2016 and are positioned for planned refinancing to start in the first half of 2017. So, with that I’ll hand over to Paul.

Thanks Les. Good morning.

Thanks guys. I think 2016 was a busy year.

We had a lot planned. And then we had the unplanned event at Jubilee so it was even busier than we expected when we went into 2016.

But if we look kind of broad outcomes, TEN was delivered on-time, on-budget which by any measure of the industry is an exceptional result. Jubilee did serve us up a big surprise.

But I think the team did an exceptional job there as well in terms of just managing that and that was a broad team, it wasn’t just kind of operational, it was operational and then the project team transforming the problem into just a fairly straight-forward project. And the whole kind of financing team and IR team in kind of managing the communication of that issue and obviously very importantly the insurance area.

In Uganda, we’ve been involved in Uganda for some time. It was I think a very important 12 months in Uganda when you look at the pipeline group was finally decided.

The production licenses were finally issued. And the asset deal was done earlier this year that no hedges of and supports and early FID.

In Kenya, obviously we know are focused on a standalone pipeline and there is a lot of activity I’ll talk about in terms of supporting the commercialization of the substantial resources we have in Kenya. And thinking about all of that was actually delivered by streamlined organization, as Les said, the overhead of the company has come down substantially, we’ve reduced the headcount by over 40%.

And yet that streamlined organization delivered everything at the same high standards that we expect. And I think nothing highlights that more than we had an exceptional year from a safety point of view last year.

We actually, one of the key metrics that you see across our industry and any other ones is kind of LTI’s loss payments and last year our LTI level was zero. We had no LTI throughout the year which I think is a great kind of commendation to our company that in an organization that changes a lot over the previous year.

If you look at production, it was impacted by the Jubilee in 2016 but with some excellent work and not including the insurance we managed the deliver 74,000 barrels a day last year from Jubilee through using the shuttle tankers and the storage tanker and managing to operate throughout the year very safely. That contribution plus the contribution from TEN is around top, strong performance from our West African portfolio, led us to kind of 65,000 barrels a day for the full-year, and net total from the West African portfolio.

And then obviously the additional 6,000 barrels a day from the European gas. As we look into 2017, we expect the West African portfolio to deliver 78,000 to 85,000 barrels a day and the gas production to remain constant between 6,000 and 7,000 barrels.

Looking out for the next couple of years, we’d expect to see modest growth as we get and I’ll talk a little bit about this Jubilee and TEN ramped up towards their capacity. So, that will give us production growth in the short-term.

But I think as the graphic shows the important step-up in production comes at the early part of the next decade. And if you look at the underlying production we have and where we expect it to be, you put in Uganda, which is now on a track to get to our share 23,000 barrels a day or 10% equity, and then depending on where we go to in Kenya leaves us with growth in production to somewhere between 120,000 to 150,000 barrels a day at the early part of the next decade.

On TEN, very successful delivery, it’s actually fairly real and we’ve obviously looked at the stats around these mega projects. And actually the performance of the team on TEN puts them in the top, into the top quarter of global industry project delivery which I think is, it kind of shows the company a total size can deliver these mega projects as well as anyone.

It’s disappointing we can’t take advantage of the facility which we’ve tested well over 80,000 barrels a day due to our inability to drill additional wells. And but we do expect to drill in moratorium to be removed in the latter part of this year, with net loss basically gives a final outcome which we expect to be around September/October this year.

I suppose the good news is that process remains on track. The hearings, the final hearings for that loss tribunal are ongoing right now.

And that’s the date that was originally set for these final hearings. So that suggests us everything is on track and we will get an outcome in the latter part of this year.

And then in the meantime we’re working hard to try and optimize what we can from these existing works on TEN. So, we’re working to deliver the 50,000 bottles a day and exceed it if we can.

And then the other, the team are working hard to look at restarting drilling in the early part of 2018. And as always, there is always a benefit somewhere, I mean, one thing will have plenty of data as we look to try and optimize the position of those future wells remember, we’d always plan for 24 wells in TEN.

We’ve got 11 available at the moment so we will drill up to another 13, so we can use the common data that is coming in to optimize the location of those wells. And then obviously the external environment should have a positive impact on the cost of those wells going forward.

On Jubilee, the mediation projects are ongoing. We’re just in the final throws of spread-mooring the vessel.

We’ll be doing the pulling of the cables, all the equipments there, the anchors are laid and we’ll be pulling the cables in the next week or so. And we expect to have the vessel spread-moor by the end of the month.

The team, have done, as I said an amazing job to kind of get us to this point when you think about where we were kind of roughly a year ago. Importantly as Les says, we’re receiving the insurance payments, all the costs that we incurred last year, whether it, be in loss reduction or OpEx or incremental OpEx and incremental capital have been repaid for last year.

So we’re good until year end. And the team are now working on a kind of monthly take payment scheme so that as we expand we will get the money refunded from the insurance company, so that’s been handled incredibly well.

As I said, the first phase of the project is almost complete. And then we’re just progressing the final phases to really set the FPSO up for it’s kind of 15, 20, 25-year life.

So that’s what we will do towards the end of ‘17. And then the final part is looking at the offloading deals already under feeds, work on that.

And I would expect to be implemented in first half of 2018. In the meantime we’re looking for ways, obviously we are covered in terms of the shutdown this year from a business interruption but not all of the parties involved in Jubilee and especially the government, are covered.

So, therefore as you’d expect, we’re working hard to try and reduce that shutdown period and try and optimize it as best we can. As we progress through the year, you’ll see on the slide, the capacity of the FPSO starts to ramp back up again.

We were constrained by our ability to off-take from the vessel. We now have two shuttle tankers and a fuel drive in one.

So that gives us a greater flexibility to off-take and with the spread-mooring we should be able to stop to ramp up production, currently we’re in excess of 100,000 barrels a day. And we’d see capacity going up towards 110,000 in ‘17 and then going beyond that as we go into ‘18 and move over to the off-shore loading buoy.

So, we’re working hard, that then leads us to kind of the greater Jubilee fuel development plan that was submitted to government, whereby we’ll be talking to the new government in Ghana. About that, and we’d expect to have that approved around middle of the year.

And again that sets us up to make sure that we can go and add well capacity as we require it in 2018 to make sure we can maintain fuel production in Jubilee in the foreseeable future. Just before I go off Ghana, I thought I’d kind of put this, and we can sometimes get worked in the details of the kind of year-on-year activities.

But I think the important thing to takeaway is to recognize that in Ghana, we’ve got a very low-cost operation. We are on-track to get operating cost down to $8 a barrel.

You’ll see that the kick-up a little bit in ‘17 but that is just because we’re having the shutdown and we already planned to do our kind of multi-year sub-sea work in ‘17, what we see is a bunch of non-routine work is being pulled into ‘17. You need to think of that as kind of smooth and that’s the year average.

So the trend is what we’re actually pulling work of ‘18 and pulling it into ‘17 which is inflating OpEx this year. But we’re very much on-track to get it down to $8 in 2018.

As you can see from the charts, we’ve got a massive resource base, when you take into account the kind of three P type levels were up 1.5 billion barrels. We’ve not even produced 200 million barrels yet.

And again, we are working for the seismic in the fuel to try and get after that upside potential. And Angus and his exploration team are looking at near field.

So, I think the message is, we have a very long journey to go in Ghana and is very poised that there is a lot of resource space in this low-cost operation. Going over to East Africa and Uganda, obviously we talked in detail before about the deal and the transaction delivered through vale for the asset being sold.

And we consider that. I think what it does is it provides Total with a greater control of the businesses.

We hand over operatorship in the Uganda to them at completion. And then they can drive the FID towards year-end with the government’s full support.

So I think the transaction actually plays well into the government’s desire to get this thing sanctioned at the end of the year. And their desire to get First Oil as early as 2020 or the consideration is somewhere around 2020, 2021 for First Oil.

And also outlines all the parties with respect to the pipeline. So, the project itself is making good progress.

We’re kind of working through feed-by-feeds are underway. The ESIAs and all the component parts that lead up to sanction are well underway.

And I think we will achieve sanction if not by year-end very close thereafter. And as you can see from the chart down in the bottom-right, the light blue shows the scale of the capital that will be covered by the deferred payment of the total first phase capital.

So we do have some capital exposure after First Oil but as you can see from a Total point of view, the dark blue is much less. And it’s fairly light post First Oil.

So, significant asset for as going forward, it will contribute to production growth of kind of 23,000 to 25,000 barrels a day in the early part of the decade. And then finally on to Kenya, obviously with the decision on the pipeline, we’re now focused on the standalone pipeline in Kenya.

And what we’re doing is pressing all the aspects to get that project sanction in 2018. Angus will talk about the E&A program that we’ve restarted.

We’ve completed the first phase of our war injection trials which have been successful in the Amazon field which kind of reassures us that we can do what the flood developments in these fields in Kenya which is great news and very important. And we’re also pursuing the early oil pilot which will actually support fuel development because what it will do is it will provide a lot of implementation experience for the government of Kenya who are new to oil and gas for Turkana county government, who are new to oil and gas the local community.

So we’re all working together to do a lot of the things at the moment in respect of early oil documentation, agreements, working together. Well let’s just agree, rehearsal for when you get to the full field developments, those aspects they might not appear important are very important to make sure when we get to full field, we sanction it, we actually have a smooth run through that sanction.

And also, it will give us some quite important dynamic data. So, really again, you look forward to growth, we’ve got a low-cost asset $25 to $30 a barrel, development cost, when you do look at upstream tariff and OpEx.

And it will be a key part of Tullow’s growth as you get into the early part of the decade in terms of cash flow. So, just to summarize, it was a very busy year.

But actually has positioned us very well as we can return to growth into ‘17 and ‘18. With that I’ll hand over to Angus.

Thank you, Paul. Good morning everybody.

So, as you’ve heard Aidan, Les and Paul say, actions been taken, business is reset. We have a solid business base.

So we’re able now to focus on growth. And exploration remains very central to our long-term growth strategy.

In that strategy, we focus very much on low-cost high-margin oil-plays. No more complex wells in our programs, keep it simple.

We have a portfolio as a result of high-impact prospects suited to the current environments, this is work that we began several years ago, but it’s coming to fruition now. And our plays are economic add to lower oil prices.

We’ve been working hard whilst we haven’t been drilling on our seismic and our geological assets to create and high-grade our prospects and also taking advantage of the current environment to add attractive acreage to build on our exciting prospective portfolio. Basically of three buckets of growth options to work with, absolutely no shortage of opportunities, it’s very exciting period for Tullow Oil as we look forward to period of growth.

Our growth options in West Africa and to extend revenues by supporting our plans in the Greater Jubilee area, extending production plateaus as Paul said, addressing the near field exploration opportunity. In East Africa, the focus of exploration appraisal is to build value, is to drive towards that 1 billion barrel basin potential that we see in the South Lokichar basin in Kenya, more on that in a few moments.

Supporting development there and also looking to a Pan regional infrastructure led opportunity in East Africa. In our Frontier exploration, exciting prospects in Africa and South America, and I’m sure you are particular exciting set of opportunities that we have in what is probably the industry’s hottest spot at the moment, I said Guyana Suriname Basin where we’re extremely well positioned having anticipated this outcome several years ago, we have some great acreage and I’ll show what that’s leading to.

We’ve also got some great positions already in our portfolio in Mauritania and Namibia which should be working up. These low-cost material plays, meanwhile our new ventures team has been busy adding and working on adding new licenses based on these light-oil plays, so in-short, some very exciting transformational exploration opportunities, coming up.

This is just a map to summarize the activity outlook for 2017. You’ll notice that it’s a year of low-cost seismic to create the prospects for 2018/2019 and beyond.

So you see seismic acquisition and processing in Guyana, Jamaica, Mauritania, Uruguay and Kenya. Some non-seismic methods in Zambia are planned.

And in Ghana as Paul said, we’re supporting the production and development asset there with very exciting 4D seismic in Jubilee. But looking at the drilling, we are drilling, we’re back to drilling, in Kenya, we have a four plus four well campaign in South Lokichar.

We drilled one of those well so far and it came in as a success. That’s a route and I’ll show you more on that presently.

And we’ve got a great game-changer well coming up potentially in Suriname Araku later this year, and more on that presently. So, let’s start with Kenya, what’s going on in the exploration appraisal of the South Lokichar Basin there.

What we’re basically doing is, working, driving towards that FID in 2018 that Paul talked about. We’re working on four fronts on exploration, on appraisal, on water injection and on the early oil palace theme that you heard Paul talk about.

These are four critical elements that will drive towards the FID 2018. But on the E&A side of things, let’s look at the map, the map shows here the outcome of 12 exploration wild cat wells.

They discovered oil accumulations you see these green blobs on the map. Some of these have been apprised and total we’ve drilled 22 appraisal wells for field delineation and for testing.

And that’s resulted in 750 million barrel mine resource estimate as been discovered. If I add another layer to this map, you’ll see the significant upside potential in these prospects and leads in these orange and yellow polygons.

And you’ll notice particular interest in cluster of prospects in the Northern domain, up around the Etom discovery, and which revel to extend with route-1 discovery which we announced a few weeks ago. This northern area, which I’ve highlighted here in a green dash triangle, is particular in, particularly on the back of the Etom-2 result, which was our best and thickest quality reservoir.

So, the focus of our four plus four well campaign is in this area. The rig has since moved from route, the significance of the route, I should emphasize again is that it demonstrated the charge oil charge is migrated to the very far Northern end of the basin.

So you can see that the cluster of E, we call them the E-prospects, so Erut, Ekadeli, Emekuya, Etete, Etilir, these have been substantially de-risked by the discovery in oil at the very far northern limit of the basin. But meanwhile while we digest that result with move to rig down to appraisal work down in the Amosing, we’re currently drilling in Amosing appraisal well there.

The rig will then move to appraise Ngamia before returning to the North to complete the rest of the planned program. That northern domain in the green polygon which is really attracting our attention has an unrest volume potential of about 300 million barrels.

So you can see that’s one short way to get through to the billion-barrel basin potential that we see in the overall basin. But also just looking at the statistics, to have made 10 discoveries out of 12 wild cats, underlines how much more running room there is in this basin, because this basin nowhere near creamed, it’s got a lot more to deliver, so very exciting.

Now the other thing about this opportunity and it panders to the strategy as these are low-cost on-shore wells. We see $4 million to $6 million net to Tullow, that’s a gross well cost of about $10 million.

Now if you compare that to previous years a $10 million well today in past might have cost $25 million. Now that reduction in some part due to deflation but it’s mostly actually due to significant performance improvement in fields and in the operation of our drilling activity, so really good progress there.

And I believe we can bring that cost down even further. So, let’s turn now to our other main drilling event this year.

That’s the testing of a new play concept out in the Guyana Suriname Basin. Now the Guyana Suriname Basin as I said is the industry’s exploration hotspot at the moment.

And over the last few years we’ve built up this great acreage position. This acreage position in yellow on the left-hand side on the map is somewhat like a baseball catcher’s mitt or a trap’s claw.

It’s sitting around the edge of the basin on near the shelf-edge brick. In the grasp of this glove if you like are the oil discoveries at Liza and Payara.

That’s where the kitchen is, that’s where the oil is being generated and we’re sitting around this kitchen to catch the oil as it migrates through to the beach actually. We actually see in Guyana the green diamonds are showing where the seeps occur on the shore.

And in Suriname the Tambaredjo oil field on the shore also good proof of oil migrating from the deepwater through - over the shelf-edge, through the shelf to the shore. Let me look at Araku on the right.

This is in block 54 in Suriname. It’s a giant prospect over 300 square kilometers closure.

It’s a four-way structural closure, it’s another stratigraphic trap, this is a structural closure it’s a dome-shaped structure which is a good safe type of lower risk type of prospect to go for. And as I’ll show you in a minute, it’s got good seismic amplitude to support.

Furthermore this is a low-cost well, this is estimated to be $14 million net to Tullow, we’re the operator 30% partners Noble and Statoil will be drilling this in the second half of 2017. See if we can pull it forward if we can.

This is a lot of follow-up potential in this area. It’s not just this play.

There are other plays there are stratigraphic plays, carbonate plays, so great set of opportunities. We’re hopeful for Araku, Araku is our best prospect in the portfolio.

But should it not worth, there is a lot of alternative play types to follow-up in this rich acreage. Just one more point before I move to show you a bit more on Araku, just let me tell you little bit more about these well costs.

The $14 million net to Tullow relates to about $40 million to $45 million gross well cost. Now if you compare that to previous years that would have cost about $100 million to drill.

So you can see quite very significant offshore cost deflation in the sector that we’re taking advantage of so from previously $100 million to $40 million to $45 million today. But we’re also, as I say, helping keep these costs down by working on plays or in shallow water.

This is only in a 1,000 meters of water, so this is not the same as these ultra-deepwater plays, we’re on the shelf here, down around the plateau. Okay, let me show Araku.

So, this is the, this giant four-way closure, that we’ve identified on very high fidelity 3D seismic. And you can see from the texture of the map they get an impression of the high fidelity of this seismic image.

The brown is the top of the structure as it deepens away on the flanks towards the green and the blue. I just want to highlight one contour here with the blue line, so this is a structural contour.

And this is a contour that’s been put together by our structural mapping capability. Now the interesting thing is, and we do jump to what our geophysicists have been able to do.

They’ve been able to process the seismic to highlight and accentuate where we think there is oil in a reservoir. And the very interesting thing is, when we merge these two work streams, when we merge the structural mapping with the products from the geophysicists, they overlap very precisely like a hand in a glove.

And when we see this very strong conformance to structure, our seismic amplitude normally, it’s good indication of the presence of hydrocarbons. Obviously there is still a risk, this is still a wild cat well, but this is really one of our strongest prospects that we’ve ever seen actually in the last decade.

Now, just for some scale, I overlay here the Jubilee field and unit area outlined just for comparison, so you can see the Ghana acreage size just dropped on top of this, just to give you a sense of the scale of this prospect so very exciting, drilling out later this year. So, Guyana, further to the West, this is our Orinduik and Kanuku license.

You see the map on the left-hand side. With a cross-section there on the map from A to A-prime which goes from the shelf out and over the Liza field discovery by Exxon 2015.

Now, you’ll see on the section on the right-hand side, I’ve put a green lips around the Liza field in the deepwater there well over 2,000 meters of water whereas we’ve picked our acreage and our prospect in 100 meters of water. So this was a strategic move that we started to implement in 2013 or ‘14 to get these acreage positions to access these same very material plays.

But to do it in shallower water setting in order to reduce not only the exploration cost but also the development costs and improves the development economics. So you see here we’ll be able to reach this Amaila prospect at a net cost of only $15 million net to Tullow as a non-operated well there in the Kanuku license.

You might remember, last time I showed a slide similar to this, I highlighted the Kaieteur prospect, if you look at the map on the left, you’ll see Kaieteur, Amaila and we’ve also got Kamarang. So, last time I showed you Kaieteur, Kaieteur is still there, it’s a strong opportunity, I just thought this time I’d show you another one Amaila, which is equally exciting.

Okay, now, looking at our Africa positions. And a strong acreage in Mauritania and Namibia, in Mauritania, through series of relinquishments and acreage trimmings, we’ve hunkered down on to this core asset position, around C10 and C3 which is really driven by the presence of the oil kitchen.

So we are very purposefully not looking for deepwater gas, we’re looking for oil near the shelf edge. And we’re going for the oil play in Mauritania.

Low-cost high impact prospects, very clearly imaged on 3D seismic, just to sharpen up the image on some would be acquiring some seismic this year for drilling kind of 2018, ‘19. And then finally, in Namibia, we got some great leads here identified.

You can see the leads Osprey, Albatross, Cormorant, Seagull, etcetera. Turbidite fans, multiple cretaceous leads, high-quality 3D seismic survey.

Now whilst this may look like a deepwater image, in fact the water depth is only 500 meters. So this is the same concept, just trying to get access to Turbidite reservoirs, high-core Turbidite reservoirs but in a low-cost setting.

So, just in wrap-up, exploration is central to our long-term growth strategy. We’re focused on these low-cost high-margin plays and we’ve got these great set of opportunities and options in our West Africa portfolio, our East Africa portfolio and in our frontier exploration in Africa and South America, so transformational exploration opportunities ahead.

And it’s great to be back into a focused growth mode. And with that, over to Aidan.

Thank you.

I think we’ll just open up to questions.

Hi, Dragan Trajkov from Stifel. You keep talking about free cash flow.

And given that you’re almost 80% hedged on the $60 oil price, can you give us the sense of magnitude of free cash flow for this year at let’s say $60 is our oil price?

So, just to give you an idea, like you say, we’ve got the hedging as well as the any production loss adjusted by the BI insurance of $60 per barrel. So the way to think of it is that $50 per barrel, free cash flow would be in the region of about $250 million.

And if we work to get to $70 a barrel, it would roughly double.

No more questions. I’m falling asleep.

I felt Mark was going to get first, sorry, it’s Brendan Warn from BMO Capital Markets, just okay, one question. I guess, Paul, you’re taking over soon, I know you a long-time Tullow employee.

It’s good to see the company back on a firm footing. I mean, what vision do you have the company going forward it’s great to see Angus having more than say one slide at very thin budget this year into the next year.

But can you talk about the opportunity set that you see in Africa? Obviously you are hamstrung by your debt position still.

But just, what could we see from Tullow going forward, obviously in your sector you’ve had the likes of Aker BP last year, you can see that there have been some companies that have transformed. What’s your vision for Tullow Paul?

Probably more of the after April when someone in the seat. But I mean, I think if you look at the presentation, I think the big thing this morning is we’ve kind of reset, restructured that’s been ongoing, it’s been part of the plan.

Les’ point about G&A taking $600 million kind of over the cost base over the last three-year period and I think we’ll probably exceed that. So, I think what we’ve done is, over the last couple of years, built the right team.

And the point I made in my presentation, you shouldn’t think well, you got less people, you’re streamlined you’re not going to meet this timelines of the aspiration. We’ve got - I think we’re in better shape than we’ve ever been from a teeny point of view.

And the efficiency of that team and the collaboration of teams, sometimes less is more. So I think we got the right team.

I think Ghana has been a tough year, I suppose in some ways disappointing twice because we did such a fantastic job of getting TEN on stream and then to have an inability to use you got over 80,000 barrels a day capacity sitting and you can’t guess because we can drill wells. But that’s fine.

We just got to look on the positive and say ‘18 will be a good strong year in Ghana because we’ll build significant cash flow in Ghana across Jubilee on TEN. And out there the cost base is, as Angus pointed out, it’s reduced significantly, deepwater well costs are down by probably more than half.

So, there is opportunity really to optimize Ghana and have a massive cash flow coming from Ghana steady low cost to any oil price. And then East Africa, the deal that we’ve completed as a team in Uganda gives us 23,000, 25,000 barrels a day in 2020/2021 as it rises up the plateau.

So, I think what we have is a very solid footing between Ghana and Uganda, Kenya, we’ll move Kenya forward in a similar sort of way. And then, there is a reason why there is a lot of slides on exploration, we’re an exploration led company and we want to get back to exploration and just like I showed on Araku there is a sort of thing that excites us about transforming the company and return to growth.

So, I think the big message really for today as opposed to roughly April, we’ve all worked hard to reset the company and restructure it. And we enter ‘17 in a very strong position.

And I think the RCF you should kind of read a lot into that. It may just be a one-year extension, but I would read a lot more.

That shows very strong relationship, very strong support from the banks, when they very quickly, I mean, we kind of expected inside today but the team kind of put it through very smoothly and very quickly. And it was kind of heavily oversubscribed.

So there was plenty of support there for what we were requesting. So that kind of bodes incredibly well as we head into the RBL.

So, we’re in a strong place to return to growth.

Thanks. It’s Mark Wilson from Jefferies.

I agree with all those points. But it follows on from that.

So, it seems like there is only really one overwriting corporate risk still out there, maybe out with your controlling that, is the ongoing border dispute with Cote d’Ivoire. I’d just like to ask is there a scenario where the outcome of that isn’t a simple yes/no return to existing borders or could be some kind of shared scenario, some movement, some let’s call it messier scenario than what we’re all hoping for?

We’re not party to the Tribunal. But the Tribunal is currently hearing, and then they will go into recess and make the final decision in the third quarter, or the fourth quarter of this year.

I think whatever decision they make, if the leave the board the way it is or if they move it, it shouldn’t make any difference to us. And we’re assuming that once the Tribunal has ruled whatever where it rules, we’ll get back to drilling.

And we have very good relationships with both countries, we’re in both countries. And obviously we’re talking to both.

And I think Ghana and the Ivory Coast. Again, the governments have good relationships, especially the new government in Ghana.

So, we really don’t see how it can, not work, there may be a different split of the revenue for the government’s share but for the contractors it should be exactly the same.

It’s James Thompson from JPMorgan. Just Angus onto, going back to exploration.

I think Araku looks like a particularly interesting prospect. I wondered if I could just drill down into the details, you’ve hopefully provided that.

Just in terms of the source kitchen in Mauritania you gave us the size of the kitchen, you talk about this glove. I mean, how big is that oil kitchen and how far does the oil have to migrate to get to Araku?

Then the second part of that is what the reservoir, you’re targeting? And then two final points, do you know if Liza’s fill to spill and everybody seeps that you identified being calibrated to the Liza Oil?

Okay. All right, so if you flick to the map just it might help.

So, the map on Slide 21 and your books, I think you’ve got the books. You can see there is sort of baseball catcher’s mitt of acreage around the Guyana Basin.

So really everything out there in that domain called the Guyana Basin outboard of the dotted line is oil matures source rock, yes early cretaceous source rocks. The reservoir that we’re targeting in Araku is a Maastrichtian, so younger cretaceous Turbidite sand, which came off the shelf, off the continent and it was actually heading towards block 47.

So you see block 47, we’ve got more Turbidites out there over the shelf-edge brick. But Araku is a pounded Turbidite and that stole if you like it ran out of energy before it got to the shelf-edge brick and settled down over the dome, over the Araku dome.

And Liza’s fill to spill, well we really have to talk to the operator for that one. But what we are seeing from where we can see is they’re having mixed results.

They’ve also had lot of success in the patent Liza. They’ve got 29 meters of oil in Payara which isn’t such big number at Payara.

And it had a dry hole at Skip-Jack. So, our play concept involves explores in the outboard having mixed success.

We want them to have some success but not 100% success. And because every time one of their traps breaches it spills up into our play domain.

And we have seen mixed results out there. But some great results from Liza.

Liza is a big success for that joint venture. So we’re very happy for them.

But we’re also I’d like to see an occasional dry hole as we have seen, because that’s good for our play.

Good morning, it’s Al Stanton from RBC. Paul, assuming business returns to normal in Ghana in 2018.

What’s the environment going to look like with the field development of Jubilee and drilling recommencing at TEN? Are you going to have two rig campaign or are you going to see a material increase in spending there?

I think that’s one of the things we’re kind of considering at the moment. So we’ve got time, we’ll look through ‘17.

Certainly what we know is that if we want to have a two-rig company and we can, because there are plenty of rigs. So we’ve got that flexibility.

And I think the thing we have is which we haven’t had before is the flexibility to kind of almost turn on and turn off rigs. So, I think what our plan is to kind of look at the performance of Jubilee through the year as we kind of ramp up the capacity.

We think that kind of peaks, the daily peaks will see this year it will be higher on Jubilee than last year when we spread and have the two shuttle tankers. So, we’ll monitor the well capacity there and decide how much well capacity do, we need to add in ‘18.

And then obviously we’ll be monitoring TEN, we do know we need to add wells on TEN. So that will be a priority in terms of starting drilling.

And then I think what we’ll do is we’ll together a plan which will either be a one-rig plan or a two-rig plan as we go into ‘18. And it just kind of depends if you kick-off with two rigs you can accelerate the ramp-up but there is a cost to that because there will be some kind of inefficiencies running to on longer, single and we’ll just be looking at the offset between those.

A follow-up, can you touch on where the gas pricing and sales are at the moment in Ghana?

So, in Jubilee, if you recall we had the 200 Bcf which we put to the government without any cost to support the build of the gas plant that we export to. So they currently are still ticking so we’re still supplying that 200 Bcf.

The associated gas in TEN, we’re just trying in actually at the moment the gas export pipeline from TEN to the manifold, which basically Jubilee and TEN come together and join and then they go in a single pipeline to the beach has been tied at the moment. And really our expectation is we will supply some gas from TEN but it’s likely to be the associated gas which has a kind of very nominal pricing given association.

It’s when you get to non-associated gas which I didn’t mention, but I think as you look at future years with the current government that appear to be quite focused on trying to commercialize gas and make it more of gas. And I think that will require pricing that causes us to go and explore and develop gas offshore in terms of non-associated gas.

So, I think that’s an opportunity in the future. And you’ve seen the gas price that, the Sankofa development I understand has a gas price up in the kind of $6 to $9 and certainly West African gas pipeline is up in that sort of level as well.

So, there is a gas opportunity at the right time.

It’s Rafal here from Merrill Lynch. Just a quick question on your net debt EBITDA target of 2.5 times.

So, with the Uganda transaction effectively done, I was wondering what if you had any more color on your timing of achieving that 2.5 times target. And is that predicated on for the disposals for example Kenya or not?

Well, I think the first priority that we set ourselves was to get all the major projects behind us, which we’ve done. And then, to look forward in relation to CapEx going forward and that was farm-units and Uganda so they were the main things that we target to get done first.

And that left us in a position where we had very much a controlled CapEx program. The issue then was to, obviously, we saw ourselves accelerating the cap reduction here highly geared towards oil price increases as less at $10 increase in the oil price is quite dramatic effect on our cash flow.

But also as Mark was talking about ITLOS, ITLOS is a very important thing for us to get that out of the way because then we have the flexibility in our portfolio to manage our portfolio to de-leverage even faster. So, I think there is a number of mechanisms that we have to then de-leverage the balance sheet faster than just normal organic growth.

When do you expect to hit to half times EBITDA assuming their disposals?

We’ll be half inside the target but it’s just something that we feel is the gearing ratios that we should have long-term. And don’t forget it’s not just reducing that we will be increasing our profitability and our cash flow as well.

So it’s actually moving in both ways towards.

Thanks. Michael Alsford from Citi.

So, a question just on the non-operated West Africa business have occurred. So guidance this year is for quite a steep decline in that production basin off my memory of about 20% decline from 2016 levels.

I’m just wondering given the limited spending in that business in ‘17, should we expect at similar level of percentage decline into ‘18?

Yes, I think on the West Africa, and obviously we used to spend about $200 million a year on West Africa, last year our spend was I think $30 million or $50 million last year and previous year was also I think $75 million to $80 million. So, there is quite a significant reduction.

Actually we’re quite pleased at how well that’s held up, like last year we remember we always kind of push the case to $200 million meant that we somehow achieved that kind of a plateau of about $30 million and we’ve been running it for quite some time after the $200 million. And despite the reduction in CapEx it was reasonably resilient last year to $28 million, I think we’ll see more of the impact this year.

I think it depends. I think we budgeted this year for kind of $30 million to $40 million.

There is a bit more noise from our operators that they may be more inclined to going back to working some of the infill activities. And that’s more likely to be kind of planning this year for a restart next year, there is something we could do this year maybe on the onshore.

So, it’s kind of uncertain. If we keep the CapEx tap closed you will see significant reduction.

And we’ve kind of built that into our forecasting that we recognize if we don’t spend money we will see further decline. It will slow, it won’t continue at 20%, it will fly north as these things do.

But that raises also the ability to step back up. I mean, we would be happy spending a little bit more because we got the opportunities across the portfolio.

Thanks. And just a quick follow-up on Aidan’s point around profitability improving.

I guess one of that’s driving obviously cost down and then the target of $600 million of savings. Could you just talk about when you get to that level and I guess where that extra $100 million is coming from, I’d be glad?

Thanks.

What we targeted if you remember back and that we said that we’ll try and push to $500 million out in the business in the overall costs. And as Les said, we’ve achieved $300 million of that and we think we can get $600 million plus.

So it comes generally towards the whole business like the big cost that we had in 2015 or early part of 2015 was the starting levels and consultants which took over the business. And then is part of the MSP process, we look to how we streamline the business in relation to where the company actually works.

And the way we manage costs, so it was generally throughout the whole business. And we could see today those costs are still coming down as we get more efficient in doing things.

So, it’s general, there are no specific areas in that. But the big cost was at the start.

Stephane Foucaud, GMP FirstEnergy. A question on reserve.

There was I think about 14 million barrel added in 2016 and there was quite long-list of asset shaped with that increase. So, I was wondering where there was one that was probably more than the other.

And then, this year, there would be, hopefully the FID of the greater Jubilee area and I was wondering whether you had any update on last view on how much that could add to the reserve? Thank you.

Yes. I think the reserve’s addition was there was, it was quite well spread across those assets.

I think just by the nature of scale Jubilee there were some additions to Jubilee this year just because the scale of Jubilee that was a larger percentage of the 30, 40. But what you should think about is those West African assets, there was a good contribution across the board.

We would like to think that when we sanctioned Greater Jubilee, we don’t have either one to gage or a number at the moment. But we would expect to get that sanctioned this year and get to build into the program.

Then our reserve order is all our numbers from the reserves auditor. We would then sit and look at what we think that additional barrel - additional program would provide once it’s sanctioned by government.

So, I guess we’re hopeful if we can get that approved this year, then we will see some addition as we get to year-end. And again, back to the RBL point, we’re demonstrating even the matured assets we’re continuing to add reserves to.

Jubilee has still I think a long way to go in terms of reserve’s addition. And previously the RBL was underpinned by the P90 on TEN and that was production now that will migrate to the P50.

So they could have underlined collateral in terms of reserves is increasing as we allude to reduce the RBL.

It’s Colin Smith from Panmure Gordon. Just firstly a quick question on the adjusted EBITDA’s calculation.

I’m just curious just, to whether that matches precisely what your lenders are looking at. And the reason I ask is that the calculation last year came out pretty close to cash flow pre-tax.

But the calculation this year is quite a delta between the two?

It’s slightly different from that which we did with our lenders. I think that’s all I would say.

I really couldn’t talk about the detail, perhaps offline.

And I have follow-up questions something a completely different. You mentioned Sankofa early, and the gas price we’re getting from it.

Can you just talk a little bit about where TEN and firm gas contracting actually sits because we’ve seen at least one instance in which an operator thought he would get a certain volume of gas and then it turned out the gas market wasn’t as developed a they thought. So they found competition from other suppliers diminish the level of off-take they thought they might get.

And then in that context, I’m interested just to understand what they dynamics of the Guyana gas market might be and how firm the volumes you might have to sell into it are in terms of contracted in?

Yes, I mean, I think the first thing to see is kind of in our projections the gas revenue is completely immaterial. So it’s kind of I don’t know if it’s even 1% or it’s kind of down at that level of overall revenue is tiny at the moment.

Because the gas we export that we kind of $80 million to $90 million a day, we export from Jubilee has no associated gas price. And as a number of years you have to, associated gas price with that.

And on TEN to be honest, actually we would rather be retaining the gas offshore on TEN because we can maximize the oil recoveries through gas reinjection. So if the government decides that they prefer not to take the gas at TEN, we’d be quite happy to keep it offshore for a number of years.

We would obviously have a boulder later on where we would then sell the gas. So, the volume is coming off TEN, I’d say in the next two to three years or two years, it’s going to a relatively modest.

The gas plant there has a capacity of about 160 just know it’s running around of 70 or 80, so there is plenty of physical capacity on the infrastructure. And I think what Ghana is requiring which would be good when Sankofa comes on and with TEN is that from the power generation, if we have a shut-down which sometimes do, it causes kind of ripple effect through the power systems, whereas once we get to the point where Sankofa is providing gas, Jubilee is providing gas for the backup of TEN, you can have a then more stable supply from multi-sources.

And then I think we’ll be able to build the power base more on gas and that’s certainly I think the government’s plan. So, that’s why I see, I think just know it’s kind of a material in terms of revenue, I think as we look, five, six, seven years out, actually I think there will be a commercial gas market and we’ve got quite a bit of gas kicking around our especially around the TEN area.

And we haven’t gone looking for gas either. So, I think it’s something for the future but it could be quite important.

Could we see if we have any questions on the conference call please.

Hi there gents. A question, actually, I suppose, around Kenya.

You’re doing appraisal drilling, water testing, what are you hoping to actually prove up in the south of the basin? And what do you hope it can do for you in terms of reserves, in terms of production numbers?

And this year, will we really see that data?

So, maybe I’ll say there were injection part and then I’ll leave Angus to kind of talk about the broader volumes. I mean, I think what was important, we’ve been assuming that we can water inject and we can get secondary recovery in the development of the reservoirs.

What we want to do is actually do some test to prove that that was the case. So, the successful water injection at Amosing was quite broad because it gave us the reassurance that we can plan on our water flood development which obviously increases recovery factors.

So there is a lot of oil in the ground here. I think the factor is how much of it can you recover and so that’s why the water injection tests were quite important and we’re now moving to Ngamia to do more checks and tests there.

I’ll leave Angus talk about the volumes.

Yes, hi David, Angus here. I mean, there is a cluster of discovered oil in the south in two accumulations Ngamia and Amosing.

And the appraisal activity they’re engaged on at the moment is trying to delineate those accumulations in support of the water injection where it is going on at the same time. The Amosing well is drilling at the moment is drilling up towards the basin bound in fault.

And what it’s looking for is the transition from the higher quality outward reservoirs to the lower quality inward reservoirs in order to add, delineate the field and the most productive parts of the field. So it’s a classic sort of infield appraisal technical objective all towards helping reduce the uncertainty so that we can get to FID.

In Ngamia, which will be the next well is an appraisal well with a slightly different objective. What we’re doing there is drilling undrilled fault compartment in the Southern flank of the Ngamia field.

So it has a possibility of adding a completely new compartment to the Ngamia volumes. But on the exploration side, on the exploratory appraisal side that we’re most interested in, is the Northern part of the basin, these E-prospects based on the success of Etom-2.

And what we’d like to do there is drill Etete, another prospect that catches our eyes here, and Huya [ph]. And we suspect there may be a northern concentration of oil, similar sort of magnitude or perhaps even greater than what we found mostly in Ngamia, in and around that Etom area.

So that’s what we’re trying to do, combination of field delineation and exploratory appraisal to get to the billion barrels to drive to FID 2018.

Yes, just as a follow-up, Angus, thanks kindly, but there seems to be no shortage of oil. A lot of the issues seem to be about reservoir quality determining recovery factors in a way that Etom-2 showed up good results.

Have you actually said what the results on the Erut reservoir were yet, and how that influences your thinking on which prospect to drill next?

No, we’re still evaluating that result, what we did find was 25 meters of net pay in a 55-meter grills off section, and depth of 700 meters and the oil was recovered to surface and we have really nice internal video of the oil being decanted from the sample chamber into buckets, its good light oil. It’s not biodegraded despite being at 700 meters, so it’s coming out of the reservoirs.

We’ve also had successful flow tests on these reservoirs. And also as Paul was saying, the water injection is working.

So there is not really a reservoir issue, just needs work and information data.

So, certainly an improvement on some of the technical discoveries you had in other basins, which haven’t come to pass?

Yes, this is quite different. South Lokichar is the one we’re focusing on, this is going to be new center for production surely once we’re through FID.

Thanks kindly.

We’re drawing close to the end. If I have one more question maybe before we finish?

Thanks. It’s Anish Kapadia from Tudor Pickering Holt.

I had a question on Uganda; just to understand how it looks after the Total transaction. So, just wanted to understand better what happens with regards to your previous cost oil that you had associated with those assets, whether - how much cost oil you retain, really to get an idea of once the field is at plateau.

I think the fiscal terms are relatively harsh in Uganda, so if you can give some idea of when the field is at plateau what kind of cash flow you’d expect it to generate in, say, a $50, $60 oil price environment?

On the first part, as part of the transaction with Total, the costs basically follow the interest, so I think that would be the first thing as far as the cost pitch. Then I get cut into, as you say how the costs are.

I don’t actually have at my fingertips, I guess we can follow-up on the cash flow numbers future prices.

Okay, just one more question and then we’ll draw it to a close.

Hi, it’s [indiscernible] from Morgan Stanley. I just had a question on net debt.

Essentially you’ve said the balance sheet is de-leveraging right now. I was just wondering the $4.8 billion, was that deep-netted or if it’s not what was the peak level and even going forward in your assumptions, what would this net debt level go to by the end of 2017?

Is there any indication?

Well, I’m making no prediction on the year-end net debt because it’s, among other things will happen through the course of the year. As far as our peak, I think that’s right, the 4.8 has been the peak of our net debt.

Okay. Thank you very much everybody for attending.

If you have any further questions you know where to get hold of us. Thank you very much.