Tullow Oil plc (TLW) Earnings Call Transcript & Summary

[Audio Gap] Here, our financial situation was pretty dire. And we had a -- we did well in terms of nearly $1 billion in self-help that was through asset sales and cost savings. We started implementing our operational improvement plan and the market has helped. So all that really led to the big refinancing that Les and the team did back in May. And that really put the company in a very firm solid financial footing and has really enabled us to then start to deliver on the value-creation plan, which is based on the business plan that we've outlined in November of 2020. So that's at the Capital Markets Day, if you remember. So that was kind of the one thing really sort of resolving the balance sheet. The second big thing for us last year really has been this operational turnaround. And I'd kind of point you to one thing which gives us good evidence, which is really uptime. So the average uptime across both Jubilee and the TEN FPSOs last year was in excess of 97%. And I don't think we've ever achieved that across both FPSOs in the past. The other thing we started doing in Ghana particularly was in starting in April of last year, we embarked on the drilling program. And what I'm pleased to share is that the drilling has gone better than we expected. So we laid out kind of our plan in terms of how we were going to improve drilling and really it was based on, one, just better well designs, more intelligent wells, less complexity. It was based on a contracting strategy that was really focused on building partnerships with our contractors. And then just good old-fashioned focus on operations. And all that has allowed us to drill wells kind of cheaper, better, faster. So what do I mean by that? So we were looking at about 70 days to drill and complete a well. We've actually done that in 60. Our AFEs were about $60 million per well. We've done that in below 50. So that's a good performance, and we ended up drilling 4 wells and completing 1 just in that kind of 9-month period instead of about 3-plus wells. So operating performance kind of went well. And the last thing really that, to me, for last year was quite fundamental is that we validated the basic thesis that underpins our business set. And that thesis is that there is a big resource that is associated with the producing assets. And historically, we've underinvested in this. But as we invest, we will deliver production. So where is the evidence for this? If you look at Jubilee, Jubilee, we started the year at 70,000 barrels a day. That was gross production. We ended at 90. And the big driver was that it has better management, better uptime and investment. Similarly in Gabon, we had almost a 40% increase in production in the Simba field, largely driven through acceleration of investment into 2021. So good evidence of that. So that gives us a lot of confidence sort of going forward. So where does that bring us to -- for 2022? So 2022, first thing is we continue to focus, regardless of costs, on operating performance and on drilling. So that continues. But also, what we're looking at is upping the investment. So the financial framework that we've used this year is looking at scaling our investments so that we're cash breakeven at 65, right? And there's a reason behind this is that one is we have a non-call 2 provision on our '26 debt. We can't repay the '25 debt. So -- and oil prices are high. Our cost performance has been low. So this is the time for us to invest in our core assets, and we have a high-return portfolio of opportunities. So what we are doing is in Jubilee, we're taking the opportunity to invest in subsea infrastructure covering the Eastern part of Jubilee. And you may recall from our September presentation that shown a map which historically we've developed and focused on the core of Jubilee. The Eastern part has got about 170 million barrels of oil, EUR has not been developed at all. So the focus is to put in subsea infrastructure to help us develop that. So '23, '24, '25 is going to focus on a lot of drilling, which will look to develop the eastern part of Jubilee. On TEN, the focus is kind of twofold. So one is on investing in basically managing the decline from the existing fields. But again, you may recall, in September, we showed that the focus on TEN for us is going to shift into the undeveloped part of TEN. And what we're looking to do this year is we're looking to bring in 2 strategic wells into TEN, which will then help shape for us the future development resource potential in TEN. So really '22 is going to be about, one is sustaining the performance, in fact, improving it, and then investment. And then the one last thing I wanted to showcase for you for the TEN plans, which we're excited about, is the transformation to self-operatorship in Jubilee. And really, what we've seen over the last 2 years is a strong correlation between delivering improved performance and the degree of control that we had in the FPSO operations. So the logical conclusion then that took us 2 wells to say, if you want to sustain the operating performance, you want to bring the costs down further. And given the confidence that we have in the resource, we want to make sure the FPSO is there to service that resource development. We felt it's important to bring the O&M of the asset under our control. So that's a key kind of strategic move for us. And of course, that takes us further on the journey of institutionalizing the operating capability for Tullow. So really -- I know we don't have a lot of time, but I just wanted to frame the discussion with these comments. Nadia, please appear to then just open up to questions. And Les and I are happy to answer any questions you have.

[Operator Instructions] The first question comes from the line of Alex Smith, Investec.

Just a quick one on the 2022 outlook for free cash flow. You mentioned that you expect $750 million of operating cash flow at $75 a barrel and $100 million of free cash flow, but this includes Uganda. So we're just looking at actually for the year, this is expected to be almost net cash flow for the year of operations, excluding Uganda. And I guess this is before the preemption, but just looking at the delta of costs, we have CapEx at $350 million, decomm at $100 million. I assume that means that interest costs probably come in at about EUR 300 million as well. Is this maybe a bit higher in terms of the cost that you're expecting? And is this CapEx driven by you're doing 6 wells this year, which is slightly higher? And decommissioning looks like it's also quite high at $100 million. What should we be expecting for decommissioning going forward as well? And then just while we're on the subject of CapEx, is there going to be a decision on an additional rig by the end of the year? And any assumptions for how that would materially affect CapEx going forward?

Okay. So Alex, I'll give you a couple of comments and then Les can also kind of fill you in. But as I said in my introductory comments, I think the CapEx is scalable, right? So we've taken the decision to sculpt the capital spending to a level that gets us to kind of a cash breakeven. So that's one of the reasons why you're not seeing a lot of free cash flow, that's a deliberate decision given the depth of the investment portfolio. So that's kind of one thing. I think the interest costs are $250 million from memory, but Les can probably clarify that. And Les can also give you color on the level of decomm spend that we see next year and beyond. We're certainly going to invest, putting a lot of decomm spend this year again. In terms of the nature of the spend, yes, so one driver is that we're drilling 6 wells. That's just a reflection of the improved operating performance. But also, we are, like I said, we're investing in infrastructure in Jubilee. And also these strategic wells that we do in TEN, they're not going to come on stream until 2023. So that's why you won't see -- all you'll see that TEN is the stabilization of production, which is a consequence of the gas injector we drilled last year and the water injector we're drilling this year, but the growth in TEN is going to come from 2020 -- is going to come in 2023. Les, do you want to cover Alex's other questions?

Sure. So I can confirm the interest number that Rahul used, Alex. Then decomm, so if you look at this year, we've ended up around about $70 million on decomm and that's split about $30 million in Mauritania, $40 million in the U.K. We're around $100 million next year, split roughly $40 million Mauritania, $60 million in the U.K. and then it tails off quite dramatically. So within the sort of $25 million, $30 million range by the time we get to 2023. And it's worth just reminding, we put quite a helpful slide on our -- one of our previous online presentation. So you can pick up the annual detail, but the big drop both comes in 2023.

And then Alex, yes, the other question you had was that, yes, given the scale of opportunity set that we have, we're certainly looking -- working with the JV to bring in a second rig. So what you'll end up seeing in terms of expenditure, the nature of expenditure next year, I won't give you levels. But Jubilee you're going to see mostly the CapEx spend in '23, '24, '25 going into drilling. In '23, you'll see some infrastructure spending in TEN as we hook up these 2 strategic wells, we need a 2-well manifold, which is going to come after the Jubilee Eastern infrastructure. So -- and then we will have drilling as well. So I suspect what will happen is the mix of capital spend in '23 is going to be more heavily cleared towards drilling compared to this year. So this year, if you look at the mix of capital spend, there's more infrastructure than drilling. I think next year onwards, you'll see that flip.

The next question comes from the line of James Hosie, Barclays.

I was just wondering if you could provide any more context on how the investments you're making in Ghana this year impact production in 2023 and onwards. I guess, in particular, just the time frame for getting gross Jubilee production back to being consistently above the 90,000 barrel a day level you achieved at the end of last year?

Right. So I think this year, we're drilling, like I said, there is -- we drill and complete 3 wells in Jubilee, so there's 1 producer and 2 water injectors. And then the bulk of the capital in Jubilee is in infrastructure. Next year, we start to bring in mostly drilling, and that's going to be on the eastern part. And simplistically, the way at least I would encourage you guys to think about is you have current production levels, you have a natural decline, which is somewhere between 20% to 25% a year, right? You have mitigants that we can put in place, which are things like improved water injection, better gas handling capacity and then you have new wells, right? So last year, if you think about it, we started at 70%. The first half of the year, we kept the decline flat because we increased gas processing capacity and improved water injection. And in the second half of the year, we added wells which increased production. This year, we're going to increase gas capacity somewhat, but we don't have that kind of low base effect, which we did in 2021. So you're not going to have much litigation on the decline. So let's assume it's a 20,000 barrels a day decline. And then you have 3 wells coming on stream. So that's going to not necessarily cover the full decline that -- or it's not going to fully cover the decline. So that's kind of framework. And then you have about a 4% impact on the shutdown. So that's kind of a framework that I use simplistically in my head when I think about whether it's Jubilee or TEN. Next year, you're not going to have a shutdown in Jubilee and you then basically you still have a natural decline. But we're going to be adding production from a lot of the wells. And if you're drilling, so call it, 4 to 5 wells a year and you're adding, just on average, somewhere between 5,000 to 10,000 barrels per well in the first year of production, you can start to see how you can very quickly get to not just sustaining 90,000, but you can start to get to kind of in excess of 100,000 barrels a day, right? So what we'll do, James, is in the March results presentation, I want to lay out a framework, which is be a bit more transparent and kind of easy for you guys to work with. But I keep coming back to my basic point, which is that we've demonstrated and will continue to demonstrate both for Jubilee and TEN and for the non-off that the resource is there, and as we invest, we will create value, right? And the same model kind of applies in TEN, which is a little bit behind. So we've got a TEN enhancement project, which is really focusing on the undeveloped resource in TEN. So that's India north and south and then it's covering internal progress and [indiscernible]. So that's about 260 million barrels of oil in place. And put that in context, so far, we've been targeting only about 200 million barrels of oil in place across [indiscernible]. So you've got the next phase coming in the 2 strategic well that we drilled, will help us kind of then shape that development as we go forward.

Okay. Sorry. Just one further question I have is I understand predicting the time line to completing the preemption process is difficult. But can you just outline the steps you still need to go through and whether there are specific obstacles to deal completion?

So there are 2 steps. One is kind of finalizing the FTA with Kosmos. So we're basically kind of stepping into a deal they want to be agreed. And we just need to make sure that, that SPA is agreed. And the second then is once we read that, then we go to the ministry for their approval. And because we're stepping into a deal, James, which has already been agreed between -- so Kosmos did all the hard work in terms of agreeing all the kind of bells and whistles. So we're basically stepping into that. So we don't expect any major sort of roadblocks. It's just a question of time.

Could you give any steer on time frame to completion? Or is it just too open-ended?

Well, look, I think we're trying our best. Les is doing -- he's working hard. He's a veteran of getting many deals done in Africa, but I think he would also say to you that it's one of the things that he is going to have learned is it's hard to handicap the time. But look, we're working super hard. But I couldn't forecast the time frame in there.

The next question comes from the line of Rachel Fletcher, Morgan Stanley.

Just one from me, please, on the longer-term CapEx outlook. I think coming back to your November 2020 Capital Markets Day, you were guiding for $2.7 billion in CapEx over 2021 to 2030. Now obviously, that was before the non-operated asset disposal, and of course, this preemption. But how should we think about annual CapEx over the next 10 years? Should we expect CapEx to be higher as you take advantage of higher oil prices?

Yes. Thanks, Rachel. That's a good question. So I think our overall CapEx spend, so when we described the 10-year plan, it was front-ended with Jubilee. It was Jubilee heavy in the front end and it was TEN heavy in the back end. That's the way the plan was, right? And that had about 50 wells. It had the Eastern infrastructure that I talked about. It had development of [indiscernible] but that was in 2027. So the kind of, if you will, the 50 wells and the subsea infrastructure and all that largely remains unchanged. So the kit is the same. I think what we are looking at is the timing of that spend. And the timing of that spend on an annual basis will change as we have taken opportunity this year to say oil prices are high. Our cost structure is low. We have a window where we physically can't repay a lot of the debt. So why don't we invest and that strengthens the position of the company to be able to refinance, let's say, next year or something like that. So that's a tactical decision that we've taken. It doesn't increase the aggregate spend. It's just the timing. So I think what we did in September, if you remember, Rachel, as we laid out a kind of a 5-year window of what the kind of CapEx spend was. And what I'm hoping to do in March is to kind of further kind of update that and to be able to give you guys kind of what the moving parts would be. But overall, the investment opportunity is well defined. We're very confident in that. I mean, because we got validation of it. We're very comfortable with our own capability. I think we're demonstrating that. And now it's just a question of timing of things.

The next question comes from the line of Al Stanton from RBC.

Yes. It's a quick question about the operatorship. I understand why you'd bring the MODEC cooperation in-house. So I just want to check that it is your house that you're bringing it into and that change of operatorship isn't something that's involved with the Kosmos deal. And then following that, what is your outlook for operatorships generally? I mean, I kind of thought you were demanning and reining in activities. So I'm just wondering if there's a change in attitude across the wider portfolio when it comes to operatorships.

Okay. So I think -- thanks, Al. That's an important question. And I can't resist for saying this. Yes, we're looking to bring it in-house and the house is not burning anymore. I couldn't resist that. But on a serious note, just to be clear on vocabulary, I mean, of course, Tullow is the named operator. We have -- I think for those of you not familiar with this, we have an O&M contract. So in essence, we've outsourced the running of the FPSO to MODEC, that's both Jubilee and TEN. What we're looking to do is to basically bring in that O&M contract in-house. What that means, therefore, is -- I mean it's an important strategic move. It's less daunting in a way that's because what it does is it allows us to take control of the key decisions, the scheduling of maintenance. How we drive the day-to-day operations when something breaks, how do we fix that. Management of the back end of the supply chain. So these are all things is -- and it wouldn't lead to us hiring hundreds of people. In fact, it's going to lead to a reduction in the overall costs because what we're doing currently is, we're kind of double teaming. So let's say there's an OEM, which is a MODEC person on the FPSO. We have our own ops person who is kind of managing that person. And candidly, that's the reason why we would drive a lot of these operational performances. But what we will end up doing is we would end up reducing a lot of duplication. We would, by bringing control in terms of how we're managing the inventory, how we're scheduling maintenance. I think we would get more efficiencies. And the idea for us is that we want to, like I said, internalize, institutionalize this capability because our world view is that there will be more opportunities across the industry to take assets and to turn them around. From a cost perspective, capital efficiency, reservoir management, environmental footprint. And I think having the kind of nuts and holes capability in house and a demonstrated track record, I think, is a big plus. So that's the thinking behind. So it's very much fits with the kind of philosophy, Al, of staying lean. It fits with the philosophy of driving operational efficiency. It fits with the philosophy of driving costs. And it fits with the philosophy of saying, look, we're here to stay and we want to make money from assets and we want to build that as a strong capability.

Okay. And as a follow-up question, I'll not ask you about Kenya because I think that this has nothing to do with Kenya, but it might have something to do with Espoir and some of the fields you talk about more positively in Gabon. So should we be unsurprised if you took over the operatorship elsewhere in your current operations?

I think you shouldn't be surprised in general in seeing Tullow kind of do more from an operatorship point of view. I think that's becoming a lot more part of our DNA. We would do it simply because of an ego thing. We will do it where it would make sense. So like in Gabon, I mean we have a great relationship with [indiscernible]. I think they're a great operator. So that's one where we are just complementing them through a lot more of our subsurface capability, but there will be other instances where we can do things kind of cheaper, better, faster than other people can. And I think you'd expect to see us do more of that.

The next question comes from the line of Nick Stefanou, RenCap.

It's Nick from RenCap. I've got a couple to ask you, if I may. This one is for TEN. I'm surprised to see declines of 25% to 30% this year as well, especially we've got 3 wells in the field. And I was wondering, what does it take investment-wise to kind of like stop [indiscernible] and take production back to growth? And then a follow-up on this kind of like same theme. Post this transaction with Kosmos and there are symmetrically hard stake at TEN. How are you kind of like changing your thinking around investment there when the past used to be in towards the second half of this decade versus now? And then the second question is on cash flow. Now clearly, I mean, I'm breaking even at around $70 organically is not linking well with your peers. But I mean, you did mention it's because of the CapEx you come up and down. What do you see breakeven on organic levels in the next like couple of years?

Okay. So I think 3 questions. So firstly, on the TEN decline. Like I said, I mean, we were surprised with the level of decline last year compared to what we expected, right? So we were expecting about 25%, I think it was more than 30%. Now I think the important thing is that when you have a problem, do you understand what that is and can you fix it? And I think the answer to that is yes. So we said the problem was we had earlier-than-expected water breakthrough, and we didn't have enough pressure support, right? So how are we -- what are we doing to fix that? We drilled the Nt06 well last year, which is a gas injector that came on stream back end of the year, and that's providing pressure support to Nt01 and Nt09, and you'll start to see kind of that production tailing off -- or the decline tailing off, sorry. We're drilling a water injector in [ TEN ] middle of this year and that will help, again, their decline sort of level off. So just to be clear, and then TEN currently is producing about 25,000 barrels a day. The guidance we have given for TEN for the year average is somewhere between 22 million to 26 million. So just to be -- so on that, Nick, you don't -- what we are not seeing is a big decline in TEN this year, okay? So just to be clear on that. And that's from just that one well water injector contributing. So you'll have no producers contributing to production growth in TEN this year because the producers that we're drilling will contribute for next year, right? So to your point, Ben (sic) [ Nick ], is how do we kind of turn it around? I think it's -- the formula is very simple, which is you do things to manage the decline, so which is, in this case, drilling gas injectors, water injectors. And you've put in place the new investments, which is what we're looking to do, again, as we go forward to deliver growth. So I expect TEN next year onwards to be on a growth trajectory. Now remember, TEN is more complex as compared to Jubilee. But on a stand-alone basis, if we only found TEN, I think it's a great field, but it does require as we go forward investment, and that's the kind of plan. And the key question right now is, we had it towards the back end of the decade and is there an opportunity to bring that forward. That's something that we're working through right now with the partners. So which is what we call this kind of TEN sort of enhancement plan. I think your other point on the breakeven is -- so breakeven for us is a kind of slight misnomer because we're generating $750 million of operating cash flow, right? And then you've got to pay $250 million in interest costs. You've got $500 million. And the question then becomes is, what do you spend that on, right? Do you spend that on your existing investments or, let's say, do you use it as kind of free cash flow. And my submission to you guys would be that if you have the debt of the return profile that we do in the investment portfolio, you would invest that capital, right? And I think I said earlier that structurally, we're not able to repay the debt. So having that cash stay in the balance sheet, instead of investing in high-return opportunities, I think I would always hope you guys to support that. But that's part of the conscious decision that we're taking. So -- so I just will be careful to say, let's not get seduced by the notion of kind of breakeven on free cash flow. And if people have a deep portfolio of investment opportunities and oil prices are high, then it makes sense for us to invest to create value. And by the way, that puts us in a strong position coming into '23 when we start to look at kind of refinancing options. I hope that's -- I'll be reasonably quite transparent in terms of our thinking around capital allocation. And the thing I want people to remember is that there is flexibility in our capital spend, right? So we can ramp it up or we can ramp it down.

Fair enough.

Okay. I'm just conscious of time. Nadia, do we have time for another 1 or 2 questions or...

Yes, of course. We have time for one last question this morning. And the question comes from Matt Cooper, Peel Hunt.

Just a couple of quick ones from me. So what's the size of the 2021 working capital adjustment? And do you expect that to fully revert this year? And with regards to the Occidental acquisition, what completion date do you assume for a 5,000 BOE a day at 2022 production?

Okay. So Matt, I'll request Les to answer both. I think he has got better sense on both.

Sure. Thanks. On the first one, the number we gave at the November update was circa $100 million free cash flow for the year, which actually was a number around is probably about $115 million. And then we've given circa $250 million, so that is around $125 million. In a way, you should think of that as in 3 buckets really. One is performance, so our price cost activity improvements in there, so that's about $60 million recoveries. So that's things from joint venture partners would be about 30%, and then 30% is all timing. And the 30% timing is what then flows into 2022. So that, I think, should give you the detail that you're looking for. And then on the 5,000 barrels a day, that's annualized assuming a 1/1 completion. They obviously we're not at 1/1/2022 today. So you could just -- it's easy to the proportion on that based on whatever date you were to choose. Obviously, we're not guiding on when we might complete. But if it completed then at March, it would be 3/4 of that and so on and so forth. The investment is quite straightforward.

Just to add one more thing to that, Matt. One of the things that we did last year was we introduced a KPI, which was looking at cash flow generation, which is really driven by OpEx, G&A management, but also looking at working capital management. So there are things you could do in terms of as Les said, sort of recoveries of cash, right down to kind of we keep saying, look, every barrel sort of better than [indiscernible] dollar account. So there's been a lot more discipline in the organization around kind of day-to-day sort of cash management. So that's some of what Les described is driven by that. Okay. Well, look, I appreciate everybody's interest. Thank you all for joining. And if you have questions, you could send them into Nicola and Matt. And -- but really, this was just a taster and we will have kind of fuller discussion at the results in March. So all the best, take care, and we'll speak soon. Thank you.

That does conclude our conference for today. Thank you for participating. You may all disconnect. Have a nice day.