Tullow Oil plc

Paul McDade - Chief Operating Officer Ian Springett - Chief Financial Officer Angus McCoss - Exploration Director

Petr Grishchenko - Imperial Capital Mariana Cushanar - Nomura Asset Management Barry Sahgal - Zaara Management Gergely Pálffy - Pala Assets Nick Ivanov - Prudential Financial Andrew Mees - Babson Capital

[Starts Abruptly] overview of the message we gave this morning results presentation and then we can move to Q&A. The key message we gave this morning really were – and I am going to kind of look at Slide – the first slide in the pack that you would have access to.

Late in 2014 and through early 2015, we took some very decisive and early action giving the insolvency of low oil pricing. We moved down CapEx, especially exploration CapEx.

We dropped from $800 million down to couple hundred million and in 2016 down to $100 million. We reduced G&A costs and have already highlighted that we are very much on track to have savings of probably over $500 million over a three year period from early 2015.

Significant reductions in headcount around about 37% and we cut the dividend as of last year. The focus of the company move very much on to low cost West African portfolio to maximize cash flow and progress our TEN developments to successful first oil.

So that’s ongoing. And we continue to maintain our very strong hedging program that had been a program that we’ve been running for a good number of years, which has left us in a very good position with respect to hedging.

And our financing team put in quite a lot work last year really to secure significant liquidity and headroom. So those early actions, if you look at where we are today in early 2016, 2016 is a critical year for us.

It’s a kind of turnaround year as we go through this year; our TEN project will come on-stream. That not only significantly starts to increase our cash flow and production, but also it transforms our position with regard to capital spend.

So whereas in last year we had almost 1 billion spend on TEN. This year we’ve got about $600 million spend on TEN over $1.1 billion.

Next year that will drop to a very nominal amount of kind of tens of millions of dollars on TEN. And the real message today was that, as we look forward, there will be very much more flexibility on our capital spend.

The – with TEN coming on-stream under capital spending dropping off dramatically, we find ourselves in a position even by 4Q this year to have free cash flow generated even at the low oil prices we’re seeing. And in addition, we have very significant stakes in our assets in both East and West Africa.

So that takes us well for the future. It sets us both to kind of work our way through the current turmoil that’s in our industry.

We’ve got a very young asset portfolio, which is low cost and going to be producing by 2017 circa 100,000 barrels a day. The major part of that’s in Ghana where we were producing from Jubilee and TEN and already we are starting to see operating cost there drop.

We expect just over $9 this year per barrel, but we expect to see that drop to close to $8 and as we go through 2017, 2018 and we get synergies of those fields. Our exploration teams are working hardly.

Obviously, our exploration spend has fallen dramatically. It’s a $100 million at the moment.

But they continue to work hard to kind of restock our prospect inventory and rebuild the portfolio at this ideal time with those much less competition and a much more sensible conversation going on with governments with regard to the fiscal terms given the oil price that we are in at the moment. And then the real big message today was to get across the fact of this capital flexibility, lower functions out the other we’re going to continue to spend the high levels of CapEx that we are at today and in fact, we have the flexibility to drop our capital spend in 2017 to as low as probably $300 million even in the range of $250 million to $300 million.

And whilst we could reduce CapEx significantly, if this oil price situation continues, thereby making sure that we do continue to generate free cash flow. It has a limited impact in the short-term on our major producing assets as we’ve invested heavily in them and the – by shutting down capital spend on those assets, we see a much slower drop in production than we see the drop in capital.

So really, key messages are, early decisive action, as early as late 2014 and into early 2015 has served us well to push through the rest of 2015 and continue to drive down costs. Big turnaround in 2016 as capital spend starts to drop as we go through the year and TEN gets completed and production increases, operating cost is dropping.

So, everything heading in the right direction given the oil price situation we are in. And then we share self up very well for 2017 and if we have lower for longer that’s a position that we can ride out and generate free cash flow and if we do start to see an upturn, we will be well positioned with an enhanced exploration prospect inventory at globally attractive major projects in East Africa with kind of full cycle cost of as low as $25 a barrel and major generation of cash flow in West Africa.

And sitting there with a major priority to pay down our debt. So I think with that summary, I’ll hand over to the host to move to Q&A.

Christian, we are just seeing if there is any Q&A on the line please?

Hi, guys. Good morning.

It’s Petr Grishchenko with Imperial. I just had a question on the (RBL) redetermination.

Can you just remind me what price factor banks used last time and what would happen this March as you just pass?

So it’s Ian Springett, CFO here. The bank price tax still for them to determine for the redetermination in March.

They – and I think one thing to recognize is that even the oil prices were high, what they tend to use is forward curve and then when the oil price is, say $110, they use forward curve as $70 a barrel long-term. At the most recent redetermination, they used forward curve and around $60 a barrel and this time around we expect it to be perhaps a little bit lower than that.

not really a lot lower than that and we expect that any net capacity will lose the results of lower prices with A, trying offsets and B in any event it will be immaterial compared to the $1.9 billion headroom got itself for the year.

Got it and just to clarify the commitment amortization of $445 million in October this year that you did not account of in your $1.9 million headroom, right?

No, that’s still in place right now, but actually, when that commitment amortizes in October, that is after we have the TEN CapEx is forced – inspection is finished and then our debt will start coming down. And so actually, it’s not really necessary or worth it to in the short-term to got refinance the RBL now, to do so and we’d be paying for commitment if you like you are not going to utilize.

So, we are happy to actually let that commitment amortization occur and then refinance the RBL during the fourth quarter of 2016 or the first half of 2017.

Got it. That’s very helpful and on the hedging side, how many contracts are two-way collars?

And I was just wondering what strike on the put option you vote?

Majority of the contracts, the majority of the contract is really a two-way collars and so generally what we have is, when we got a hedging let’s say $75 downside protected, it might be around – if it’s $75 about, say $105, maybe at the top-end of the collar. So I think as you are well aware that means that the oil price is $30, it will get $75, if it’s $100 we get $100 if it’s $110, we get $105 and very occasionally we sometimes buy back in, say it about $110, - that much about recently because getting of the oil prices even that’s very cheap to do.

So, it’s probably originality that, but, say, for the most part it’s two-way collars and those collars are still pretty good.

Got it. Thanks and last if I may, on the decommissioning liability side in UK, and in North Sea, can you provide any color when this potentially can come to you considering the cost structure of those assets?

Could you repeat that question? I didn’t quite catch it.

Yes, I was just wondering, the decommissioning liability in the UK and in the North Sea, when this could potentially come to your considering the cost of operating those assets?

Oh, sorry, yes. So, on the one hand the decommissioning spend in North Sea and clearly, the TEN field and I think Horne & Wren are the two big ones.

And operators are generally looking to sort of push those out in time, but if they were to get decommissioned in 2016 for example the total cost of that decommissioning in 2016, we got $72 million and we expect to not to get pushed out and that’s all built into our cash flows already.

Got it. Thanks, very helpful.

Best of luck, guys.

All right. Thank you.

Hi, thanks for your updates. I wanted to clarify, what’s the most restrictive covenant in your RBL or RCF facilities?

The unreal covenant we have is the net debt-to-EBITDA ratio and in 2015, in March of 2015, we will lack that covenant it can give us scope in case the oil price stayed low, which of course it hasn’t got yet lower. But it’s a net debt-to-EBITDA covenant.

But we will wait, that covenants is important, it was really important it demonstrates the banks that you have liquidity and that you are able with TEN coming on-stream to pay down debt, et cetera, et cetera. So, what a covenant does really, it sort of allows the bank to sort of say, A, although, that you still got plenty of debt capacity, you’d like to have a conversation because the covenant that maybe breached in the future.

But the real conversation is also liquidity. So if we do need to relax the covenant for 2017 then we believe that that won’t be a problem.

So we don’t really think the covenant itself is really much an issue.

So, but what’s the level for that covenant in 2016?

So again, we – in our existing RBL facility, the level was, 3.5 times. We relaxed that with our banks and to have a much higher covenant level which gives us comfort where we are top right than that.

But that’s confidential information. I can’t disclose that unfortunately.

Okay, but you feel comfortable that there is a significant room.

It’s significant room, so for example, at the moment, we are well within that revised covenant and in the event, that in 2017 for example, we got, but the covenant actually was – well, that covenant was negotiated out for the end of 2016 and it start to come back down. If we go beyond that in 2017, very constant there to sort of extend it and relax it et cetera.

Okay. And then, regarding the discussion with the banks, I just wanted to understand better, from – how do you understand – how much credit did the banks give you for the TEN field, obviously, it’s not online yet, but it’s a significant resource base.

Is there – is that field is ramping up and comes on production, do you expect that would be more credit worth in the borrowing base?

Yes, so basically, what happens is, use Jubilee as an example. When the borrowing base it’s a cancellation which is – although we have commitments from the banks for a certain level of borrowing, or you can actually borrow based on the present value of the future and considering the assets.

And what they do, the banks is they value that in a pretty conservative basis using an oil price profile that’s usually pretty conservative when they get the answer divide it by 1.4 which will have cover ratios to make it more conservative. But what they do with assets in the facility, and use TEN and Jubilee as an example and the say with TEN, when the field first comes into a facility.

So TEN actually is in now or it’s just the beginning, it comes in, kind of P-90 production profile P-90 reserves higher than you would estimate costs and in TEN’s case with CapEx in – so, with Jubilee it came in as a P-90 and over sort of two, three, four years, that P-90 went to P-50. So TEN is in there for quite a small amount at the moment then if it comes on-stream and if the banks’ technical engineers get come to the field et cetera, that will go from P-90 to P-50, they’ll probably be less conservative on the CapEx and OpEx that they use and increasingly over time, we will get more PV benefit with the TEN field.

Okay. And then, one more thing on the credit facility.

Am I understanding correctly that you are just trying to perhaps negotiate and then maybe replace these two facilities with one facility that has longer maturity date, because you have this rather short duration here?

No, that’s not true. So, basically, there are two quite distinct fields which as well as our bonds.

So the RBL is a seven year facility which matures in 2019 and usually hands on RBL got four years – to mature and it starts amortizing. And I think as I explained to a previous caller that’s actually amortization – one amortization in 2016 doesn’t really matter and we will refinance it before it amortized again in 2017.

The RBL, when we talk about negotiation, I mean, another way to say that is, every six months we have a routine meeting with our banks, with all our banks, whether the oil price is high, low or medium and in that meeting, what the banks do is they come in and quite mechanistically, workout with us what the PV of the asset is and when they are looking at the PV of those assets to determine how much of the bond basis is applicable in that six month re-check in, it’s a function of new views of the asset. So for example, as Jubilee in the past and TEN in the future maturing from a P-90 to a P-50, maybe seeing better evidence of production data, evidence of cost reductions et cetera, but also applying a reduced time to the bank pricing and I think as I explained to previous caller as well.

So, really when we sit for negotiation, it is actually just say, we are the mechanical exercise to calculate what the PV is and then what does happen in that calculation is, there are conversations about, well, now we have added some more reserves in this field, based on evidence what do you think production or the costs are. So, the negotiation really not kind of we have any debt or not, it’s just about the mechanics of the calculation.

That’s that piece. And then on the RCF the corporate facility, that’s a facility which we’ve always had, it’s only a three year facility.

We’ve had it quite a long time, because we’ve refinanced at a time until before and it’s always been a three year facility which we’ve had it – bit of a back open and bit of insurance if you like and that matures in 2017 and well before it matures in April of 2017. So that facility is fully committed to April 2017.

We’ll be going to grant $1 billion again that’s tomorrow if we chose to do. But before, well before it matures in April 2017, our plan is to extend that facility to a further year before we then refinance it or do so in 2017.

Okay. Thanks for clarifying this.

Good afternoon gentlemen. This is Barry Sahgal with Zaara Management.

I wanted to ask a question with regard your baseline oil price forecasts in the current environment. I noticed that the OVX, oil volatility index has been hitting new all-time highs and I am trying to get a better understanding of how you folks are thinking about your business going forward?

Okay, Barry, it’s Ian here again. I’ll try and apply things, I’ll start off, with our oil pricing, actually when we look at things, I’d say, there is two things to say, the one is, we are, as I think we said in important introduction and we did our presentations, we are looking to make sure our business remains cash flow generative and running the business for cash and therefore $30, $40 a barrel and with our hedging of course which helps then we are in a solid position.

Clearly, I think most people in the industry would sort of say that the longer the oil price stays low, the more it is likely to rebound, but we don’t know when that’s going to be and I think we’ll be pretty foolish to try and predict that with any accuracy in terms of the timing. What we do tend to do from that business planning perspective, is to effectively base our business planning on the forward curve in the next two or three years and then we look at sort of forward curve next two or three years or maybe sort of $60 to $70 a barrel in the longer-term.

So that’s kind of how we look at it, but to be honest, at the same time, we are not doing that much big forward investments in the moment. We’ve got the TEN project behind this and we don’t have any big developments in play right now.

But in terms of looking our cash flows, with primary focus on next two to three years looking the forward curve and we kind of generally use a number of sort of $60 or $70 a barrel for the long-term.

Ian, if the price of oil were to be in a range of, let’s say $30 to $50 rather than anything more robust, what would be the most significant changes we should be looking at in terms of business modeling? What do you think would change with regard the way you position your business?

I think, well it’s, Barry, I think, that would still not last forever, but I think in the sort of medium-term as we showed in the slides today, that would mean that we will be looking to reduce our CapEx down to the $300 million or so level that we talked about today. So we will be running the business for cash.

We will be trying to ensure that we maintained our production with a little bit of erosion, but – in West Africa, both operated and non-operated, do just in that field at East Africa project in place and spending some money – bit of money on exploration to create options for the future. But it would be that kind of $300 million barrel case which basically sort of that for 2017, 2018, let’s write it down and we can show as we showed today that actually with that level of CapEx and even still specific on a barrel range, we are still able to pay down debt.

I appreciate the counter, Ian. Thank you very much.

Thank you very much. Just a question on the TEN operating cost a barrel.

If you could remind us again, how you see this for this year as the ramp up goes and 2017? I know you mentioned $9 for Jubilee and just I would like to get a feeling for the TEN?

Yes, I mean, the TEN OpEx per barrel when the field comes on stream will be quite synergistic to the Jubilee OpEx per barrel. So, last year we were just over $10 on Jubilee.

We expect to be just over $9 on Jubilee this year and when I refer to kind of 2017, 2018 heading down to $8 a barrel, then I would expect to see overall Ghana when I see in 2017, 2018, $8 a barrel then, I am looking at overall Ghana past Jubilee on TEN. And as we start of this year and we look at both fields, we’ll probably be circa 10 or a little bit below at $10 a barrel on the TEN facility this year, just due to start up and limited volumes that will probably take a little bit higher OpEx per barrel.

So the really an important year is 2017 when we have both fields producing near maximum volumes than we will get a significant number of synergies of how we operate that which is one of the great enhancements of driving down the overall OpEx.

Okay, that’s great. Just on Jubilee, for production, do you provide any maybe forecast for this next year?

I think, in one of the presentations you said the peak production could be 120 to 125 you have a working interest of 36%. I am just wondering, how far you can really go here, especially as the CapEx kind of maintenance level in 2017?

Yes, so on a gross basis, this year we are guiding 101.which kind of – at that level which is kind of similar to last year’s level. The headline numbers are little bit lower because we do have a planned two week shutdown which is equivalent to kind of 3000 barrels a day annualized, so 101 normalized without the shutdowns of 103, 104, which is similar to last year.

And then, as we go into 2017, we expect to step that up. So we anticipate a kind of annual average in 2017 of close up to the kind of 110,000 barrels a day which is starting to get close to the facility capacity, because obviously, both the facilities has a capacity of 120,000 barrels a day, there is always some downtime across the PDs of the year.

So, we’d expect 101 guidance this year and next year as we look at in 2017 expecting guidance of closer to 110 or slightly above that.

Okay, and just regarding the production of the non-operated business side, Gabon, did you think you can maintain this 30,000 in terms of working interest, roughly in the…

The production profile I showed this morning is clearly, we have been maintaining for quite sometime, Central, West Africa runs at 2,000 barrels a day and the basis of that maintenance at that level was investing circa $200 million per year on incremental activities. Last year – this year we choke that capital down to $100 million a year as our operators start to cut back on the incremental investment activity.

We see this year it’s dropping to just below 30,000 barrels a day. So we are guiding about 29,000 barrels a day.

And next year, if we continue at this oil price, we will probably continue to invest $100 million or lower and that would - we would see some decline maybe of another 10% or so for 2017. So, very much depends on how much capital we ton in often, those are kind of reasonably mature assets.

So they are more sensitive to the amount of capital we spend. So, keeping $100 million flat, 2017 will probably about 10% below the 2016 number.

But if we choose to – we could ton up the capital, it shoots oil price to recover.

Okay, okay. Thank you very much.

Thank you. Good morning.

I have a follow-up question on the last caller. How much are your all cashing costs for West Ghana including taxes and including maintenance CapEx, but excluding anything else per barrel?

Yes, it’s a tax novelty system, so really the operating cost, so we’ve got an operating cost of less than $10 a barrel. Then we have royalty, which is about 5%.

So that’s a fixed tax payment effectively. And when we see operating cost, just to be clear, that’s an all-in, it’s not a well head operating cost.

So that includes all our offshore costs, all of our burden within Ghana, so our offices, our facilities, our logistics and even the overhead that gets onto Ghana or on to the West African assets from our corporate headquarters in London. So that’s a total all up operating cost that $9 a barrel say for this year, plus whatever the oil price is $5 – sorry a 5% royalty and then taxes on a sliding scale thereafter.

So really that would be the minimum expenditure. In addition to that, what we are pointing out today going forward, is you’ve always got to assume some background maintenance capital and we were suggesting that if you really had a very low oil price and you are running the assets for cash, you might have up to $50 million kind of truly maintenance capital maintaining these two facilities.

That would be across both TEN and Jubilee. So that’s really the only three components which are fixed and so these assets are very resilient to really quite low oil prices.

Thank you.

Yes, thank you very much. For net working capital needs, in terns of changes, what do you – do you give any guidance for this year, just to – when we try to get free cash flow?

How would you think about the working capital needs, this year and also maybe next year?

I think, I mean, for us, working – we don’t actually have any working capital in the sense of inventories or things we hold rather than working capital for us really is just a timing thing and it’s just a function of comparing one year with another and accruals and so on and so forth for work done. So, I think we have a - it is just a different just why we always count on numbers and our results stay there well, so excluding working capital changes.

Okay, okay. That’s…

It really just depends on the timing of work, timing of invoice, payments, et cetera, et cetera. There is nothing – it’s no sort of algorithm or kind of basis for the same it should be growing or shrinking.

Okay, and regarding hedging, I know you guys have a relatively robust structure for this year, obviously, the class for 2017. When would you increase, that’s roughly 75% production that you have for 2017.

I mean, you guys try to reach the 70% handle I guess for oil prices, is that true, if forward curves go up then you would start increasing your hedging to get more certainty for 2017? That’s how we should think about it?

Yes, so generally what we try and do is that we try and have about 60% for the next 12 months hedged about 40% to the 12 months after that and about 20% for the 12 months after that. So, we are not – what we did have, we have sort of more than 60% to 2016 and more than 40% of 2017 excluding TEN.

Now with TEN coming on-stream we sort of factor that in and we have about sort of – I think for 2016, it’s like 52% to volumes and 64% to post tax revenues hedged and I think that same statistics for 2017 is approaching 30% on volumes and just over 40% to post-tax revenues. So, we will be trying to lay in more hedges as we approach 2017 to try and get us up to that 60% and generally we try and lay in hedges on a pretty ratable basis.

So what we try not to do is, just we can do them at a point in time, I think, use the American freight be on check quote the maximum is and one of the reasons obviously why we have $75 a barrel hedges in place for 2016 and 2017 is, if some of those obviously put in place in 2012, 2013, 2014. So right now, it’s standard today.

Hedging is not so attractive that we will be looking to put hedging back in place to protect 2017 and 2018 on the operating production.

Okay, Thanks very much.

Hi, thanks for taking the question. Just to follow-on on that hedging question there.

Is there a price at which you would not seek to hedge if we stay in sort of a very low price environment? Would you forego hedging on that hope that prices ultimately rebound higher in the future?

Yes, I mean, we hedge for principal reasons that is a very, very strong secondary reason, the principal reason which is protect our revenues. At the same time, those revenues are to get factored into our RBL calculation and so the hedging benefit gets factored into the RBL calculation.

So let’s say for sake of all events, the bank reducing the forward curve which normally does for the first couple of years or so and then a longer term price assumption after that and let’s say for sake of all given – there was a bank was using, I don’t know a $35 a barrel forward curve to 2016. Whatever the bank forward curve is, it wouldn’t make a whole of a sense to hedge for example below the bank forward curve price deck, because effectively you would be taking away that capacity as opposed to adding to it.

That would be one reason and I think generally, you will be looking to sort of hedge to protect a case that’s sort of made sense to you looking forward. So I think, obviously, $30 a barrel is a bit lower at the moment, but, it will come at price, we certainly – as you can see that, we got price protected and I think it’s in 2000, if we look forward to 2018, I am not sure it’s on the slide, but we are more at the kind of $60 or so level in 2018.

That is on that, so it’s $62, yes.

Okay, great. That’s helpful.

Thank you. And then, I just wanted – if I could get some color on kind of the $300 million CapEx number that you’ve talked about for 2017, can you just kind of talk about what the components to that might be?

Or how we should think about that? Is there any drilling of new wells associated offshore, West Africa in that number?

So, let me – I will give you a general thing and maybe Paul can talk a little bit about sort of West Africa. I mean, we know West Africa exploration wells announced for sure, but Paul talk about that development site.

But it’s a bit of a rule of thumb, but all in effectively said is, we can see spending somewhere between $50 million and $100 on Ghana. Between $50 million and $100 million on non-operated West Africa, between $50 million and $100 million ticking along East Africa to development sessions later and $50 million and $100 million in exploration.

And all those numbers, I mean I think strange as almost $50 million to $100 million, but they kind of make sense and you can make sense of the $50 million number, you can make sense of the $100 million number and you can sort of play tunes appropriately and take the midpoint, divide it by 4 and you got 300. We think therefore that 300 is the number which you could go certainly down as far as 250 and those – none of that CapEx is committed.

But I think Paul will probably tell you bit more, give you a little more color around the sort of money we might spend in West African operation and Ghana and non-operated.

Yes, just to maybe supplement what Ian is saying is that included what Ian point so is, Central and West Africa as I mentioned before, we’ve – it’s non-operated. So therefore we don’t have full control.

So therefore we’ve assumed $100 million per annum and that’s included. However, I do think that if oil prices stay at this level or reduce further and that more than likely to come down.

Our operators there are CNR and they are driving cost similar direction does. So the 100 could actually drop and then if you look at Ghana which is the other area of expense in West Africa, if we choose not to drill incremental wells, $50 million capital allocation would be more than enough to maintain those facilities and do any minor upgrades to the two FPSOs that will be across TEN and Jubilee.

And again, that’s so 150, is probably quite a conservative position and it could be as low as 100 in a very low oil price environment where you are not making incremental investments in additional wells.

And then if I just, it’s Angus McCoss here, Exploration Director, kind of the fourth component of that 300 would be the exploration budget which we would be running at $50 million to $100 million which is considerably small fraction of the $1 billion we use to spend and during the 2012. 2015 the split of that would be about 25% and to accessing opportunities and rejuvenating the portfolio 60% is on progressing our prospect inventories.

So really, basically finding oil inside our existing seismic data working up the opportunities ready for the rebound and some limited drilling activities or preparations for drilling 10% to 15%. So this is not the time to be doing extensive exploration wells.

This is the time that we work our seismic data to replenish our or hope us waiting for the rebound.

Thank you. That’s very helpful.

How should we think about your rig commitment and that you have extending out, should we go into this type of spend environment?

Yes, it’s Paul McDade here. We’ve got two deepwater rigs on contract.

One is just coming to the end of its term. The Stena DrillMAX and we’ve made a provision for that in our account so that you can find out in the numbers where we’ve stacked that really just – it was on contract for – we’d had on contract for both three four years.

We are just coming to the end of its term. We had originally obviously when we contracted to plan to have a much greater exploration program which appropriately we’ve diminished.

So we just recently, I think, last November, December took our rig in fact to offshore Canaries to really just minimize the exposure to self split the numbers on the accounts. And then other rig contract we have is the Seadrill West Leo, which is working on Ghana actively at the moment.

And that’s the only two rigs that we have.

Okay, thank you.

Yes, just say, thank you very much for taking the time to come on the call this morning and for the questions and I hope you all have a good day. Okay, thank you very much.