Premier Oil's (PMOIF) CEO Tony Durrant on Q2 2016 Results - Earnings Call Transcript

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Premier Oil plc (OTC:PMOIF) Q2 2016 Results Earnings Conference Call August 18, 2016 4:30 AM ET

Executives

Tony Durrant - Chief Executive Officer, Executive Director

Robin Allan - Director-Business Units, Executive Director

Richard Rose - Finance Director, Director

Analysts

Malcolm Graham-Wood - Hydrocarbon Capital

Nathan Piper - RBC

Michael Alsford - Citi

James Hosie - Barclays

David Mirzai - Deutsche Bank

Thomas Martin - Numis

James Carmichael - Peel Hunt

Aaditya Chintalapati - Pareto Securities

Mark Wilson - Jefferies

David Round - BMO

Tony Durrant

Morning, everybody. Welcome to everyone also on the webcast. Welcome all to the Half Yearly Results for 2016. By popular demand, we’re going to try and keep this morning’s presentation fairly brief. I’m going to summarize some of the first half highlights, a rather challenging period for the industry. But, despite that, I think, overall, a very good first half for Premier. Robin’s going to cover the performance of key assets. Richard will talk about the results themselves and the status of our refinancing discussions. And then I’ll wrap up with a look forward and Q&A.

So as I said, a challenging period for the industry. We have taken all the actions that you would expect us to take in the current environment. The question, of course, is how have we done in taking those actions? The answer is, I think we can be very pleased with our performance. So a few highlights. Production efficiency was 93% in the first half, which is pretty remarkable against industry standards. Of course, what that has facilitated is keeping production from our legacy assets more or less flat year on year, despite a natural decline built into those profiles. Towards the end of the period, we saw a step change in production driven by the new Solan field and by the acquisition of the E.ON assets completed in May.

So what we’re now seeing is daily production rates, which are actually in excess of 90,000 barrels a day, and Robin will talk a little bit more about that in due course. And that’s allowed us to up our production guidance for the year to 68,000 to 73,000 barrels as an annual average. Now, the E.ON acquisition is proving, really almost on a daily basis, to have hidden value. From a producing asset point of view, we had 15,000 barrels a day in the acquisition case. And we’re running up at around 20,000 barrels a day and expecting to average 18,000 across the second half. In addition, again, Robin will give you more details. We’re finding more and more new investment opportunities within the E.ON portfolio.

So, in every respect, that acquisition is proving to be good value. And pf course, it’s not the only piece of portfolio changes we’ve been making. We've added to Huntingdon, one of the sources of our good production performance, during the first year, during the first half, I’m sorry. And we continue with our disposal program: Norway at the end of last year, the Pakistan sales process, which continues to edge towards completion in the second half, other disposals within the exploration program. All really in line, whatever the oil price, frankly, with the stated strategy that our producing business units are going to be focused on UK, Indonesia and Vietnam with selected other exploration assets. And we will dispose of non-core assets outside of that definition. The program of cost reductions has continued. I guess we’re getting used to announcing cost reductions every six months. Richard will talk about some of the specifics of the cost reduction program, and exactly what's been achieved.

I think one way of summing up the whole program over the last 18 months to two years is to look at the total cash cost break-even across the Company. As you can see here, in 2014 that was $35 a barrel. Our estimate for this year is $25 a barrel. Obviously that stands us in pretty good stead if we see a lower for longer scenario.

On the refinancing, again Richard will talk more about this. I think the critical point really is that the combination of good production and lower cost has meant that we've been able to keep net debt under the level at which we expected it to peak, notwithstanding the volatility in oil prices. It was critical, of course, that we retained undrawn facilities. We didn't want to be going to market for new money in the current environment. We still today have $800 million of undrawn facilities and cash available to us.

We are moving into a phase where we will be deleveraging the lower we can keep that peak net debt figure as we go into the deleveraging process in the fourth quarter, of course the better. So all of this has added up to and contributed to a position where we're making good progress on the refinancing.

Let me hand over to Robin to talk more about some of the assets.

Robin Allan

Thank you, Tony. Well, as Tony just said, we had an excellent first half. We've worked very hard during this half on our production efficiency; as Tony said, we're up 93% on average. I'm going to talk a little bit about each of the business units as to what we're doing to increase our production efficiency, maintain our low OpEx per barrel and I'll talk about the progress we've making on some of our projects, the developments. I'll also talk about some of the newer projects and finally I'll end up with a few words on exploration, which we are still undertaking.

So starting with Asia, ere we've delivered top decile production performance which is obviously vital for cash flow. It's also when you combine that with the cost reduction that's been going on, is what delivers the $9 a barrel that we've got both in Indonesia and in Vietnam. In Indonesia, we've had a new high of 40 the shaking by the way of the tube going underneath this screen, in case you're wondering.

The gas demand in Singapore's been magnificent. So we have increased our share of gas, because of our high production efficiency in the first gas sale for 44%. In the second gas sale, we've seen unprecedented levels of demand from Singapore. There is unfulfilled gas demand still in Singapore and in Indonesia. What we're working at is, as how we can actually satisfy that demand. So we've got a series of projects arranging from small infill-type of projects to work on the platform and actually then for the Bison, Iguana and Gajah Puteri developments where we plan to spend about $100 million both net to premier, for about 170 bcf of additional gas that we'll be able to deliver into these markets.

We've also been talking about what other use we can have for our facilities; so in discussion with the some of the Indonesian Authorities, could -- we've got a fantastic set of infrastructure here at Gajeh Puteri going all the way down to the Singapore market? Can it be used as a first phase of development on a Tuna D Alpha? Similarly, what are we going to do with the Tuna field. The Vietnamese people we've been talking to because of our contacts obviously in Vietnam, keen to see if they can important the Tuna gas, because Vietnam is one of the countries short on gas, so quite a lot of projects in the future, all low cost opportunities to grow.

In Vietnam again we've concentrated on the production efficiency; concentrate on reducing our costs. The reserves have grown a lot. Some of you will remember when we sanctioned the project we will a little under 50 million barrels. We now, think the reserve of Chim Sao are more like 80 million barrels and because the reserves have grown because of the way we've developed the field. We're now able to do an increased length of term for our FPSO which is yielding a lower day rate on the FPSO. So we'll be there for longer at a lower cost and we're going drill two infill wells during 2017 to maintain the levels of production that we're seeing today through the end of next year.

Asia, it's the same positive story that we've shown in previous years. There's still plenty of mileage in those assets. In the UK, what we have here of course is a significant and growing production base. You're all aware, of course, that we have a significant number of assets now in the UK with the E.ON acquisition we were able to buy more assets, particularly some long-life assets, Elgin-Franklin, Glenelg and build a position in the gas basin which I'll talk about in a minute. But the critical part for us in the UK a range of assets in gas and oil. Long-life assets and assets in which we can keep the production costs low and maintain low OpEx going forward.

Let's take a look at Solan. This is an old photo here and what we're seeing here is just put in really to show what was happening and a few months back earlier in this half. So, Solan platform's on the top left of the picture here with a flow tower next door, while we were doing the commission. This is how close the drilling rig was and there's the supply vessel. Now, all of that's gone except for the platform. So we're producing away; we're injecting water about 20,000 barrels a day at the moment. We've been producing, as you know from the first production well that was on stream at about 14,000 barrels a day. The second well P2 is being wound up this morning. We'll be winding that up to about 8,000 or 10,000 barrels a day during the course of today and tomorrow.

We've already completed the tanker offloading. Some of you will remember there's a subsea, rather innovate subsea offshore oil storage tank sitting on the seabed, so that works. There were some sceptics who thought it would be problematic; actually it works absolutely fine. There's another tanker due along next week actually. The crude's being unloaded and assayed and it's 28 API. The OpEx of the field is scheduled to be about $10 a barrel for the next year or two years. So it's a low OpEx field producing very nicely.

So moving now to Catcher, which is the ongoing development, so move from production to development, I’m going to be talking about drilling, talk about subsea and then I’ll move on to the FPSO. And again, if you remember when we sanctioned the project what we predicted was various things. We came out with a reserve estimate, and I’ll talk about that in a minute. We believe that the wells will be difficult to drill and we predicated that one well in three would require a geological side track. Actually, what's' happened is that we’ve not needed any sidetracks. We’ve drilled six wells. We used this Schlumberger geosphere technology to plan the trajectories of the well exactly as we’re drilling.

So its we’ve got a whole team of Schlumberger in the office working with our guys, plotting the exact position of the front of the well. The result of that has been we’ve not needed any side tracks. More importantly, probably, is that every single well has come in at or ahead of expectations. In due course, I’d expect to see us upgrade the reserves of the field. We’re not going to do that yet. We always were at the conservative end of the partner spectrum of reserves for the field, but the results we’re getting are encouraging. That well itself, the most recent well, flowed at almost 14,000 barrels a day on test. We also predict a whole lot of weather down time, which hasn’t happened. And the reason it hasn’t happened is, because we’ve been able to not have the side tracks, we’ve been able to re-order the sequencing of the wells and avoid rig moves in bad weather.

So all-in-all, drilling program’s gone very well, it’s under budget and the reserves picture’s looking good. On the subsea side, moving to the right, the picture at the top right is one we’ve shown before and I’m re-showing it, showing it again here, because all of this is now in place: the templates, the flow lines, the bundles, the buoy, the mooring system, the gas pipeline. It’s all there, on the sea bed. We’re just doing some final hook-ups of the risers. We’re tweaking a few valves and this installation will be complete. Here’s the buoy, so when the FPSO comes along, this will already be in the sea at the end of. it’s already in the sea now, but it’ll be fully ready. The FPSO comes along, floats over, you pull this up into the turret and start your production, and that’ll be what’s happening next year.

So that’s also all below budget. The FPSO, now you’ll be aware that the FPSO was running late, so BW our contractor had subcontracted the construction of the hull to IHI in Japan, and they’ve been running late. But, to be fair, they’ve expended every possible effort in catching up. Here it is now, all in one piece, in Keppel’s Benoi yard in Singapore which some of you may recall is where our Chim Sao FPSO was constructed. We’re familiar with the yard, we’re familiar with the people, we’re very confident in Keppel’s ability. There’s about 1,000 people working on our boat, at the moment. So the key next stage is really the modules. Here, this is in Dyna-Mac’s yard, so it’s just a couple of hundred yards away across a creek from the Keppel yard, so an aerial shot here of the different modules. You can see the state of mechanical completion. Key thing here is to complete as much as you can onshore, or rather in Singapore, before the vessel sails for Europe.

The only bit, significant module that's not in the yard is the electrical E-House which is in the final state of completion in a different yard. These get loaded onto a crane barge, ferried round a couple of hundred yards, and then start to be lifted onto the FPSO in next month. So there is sequence of lifting and then there will be more tie-ins and so on. That will happen, and I'll show you on the next page. Over the coming months is the onshore pre-commissioning and commissioning while, at the same time, of course, we're carrying on drilling in Varadero and then back to Burgman.

The plan is the FPSO leaves Singapore in the summer of next year and then as I say, once it's in the field it's simply a matter of driving it over the top of the buoy, lifting the buoy in and beginning the first oil in the second half next year. We have continued to work on cost reduction, as you'd expect. The aim is to keep driving that down, we started the program with not just with all those wells and side tracks, but we had a whole load of other allowances and contingencies for weather and so on which we're gradually pulling out of the costs.

We also probably don't need the full 22 wells that we planned at the start. So, we're looking at that with a partnership and working out how many wells we're actually likely to need, given the productivity of the wells we drilled thus far. So, ultimately, we're heading towards a project that's $20 a barrel or so OpEx perhaps as much as $30 over the life of the field. But, certainly, at the early years it'll be more like $20. So, Catcher's all fine.

Moving I think to Tolmount, because we haven't talked about Tolmount. E.ON's portfolio has given us the whole piece of the action in the gas basin, of what was believed to be a tight gas play on the peripheries of the basin, but has turned out to be much better. Actually, to be fair, it's better than we thought it was when we bought it. The numbers you're seeing here will be over now and the next few months, better than what we've shown before. But just to get everyone's eye in on this page, in the bright yellow here we're seeing Premier's acreage.

In this northern part we're 50% an operator; in Artemis we're 100% an operator. And what we're showing in the solid red is Tolmount, what we're calling Tolmount Main. In the hashed area we're showing Tolmount East and the reason although they are part of the same field, we're showing them separately simply, because this part has been drilled and appraised. This part is not drilled but is clearly on seismic and so on part of the same field. So, we're just demonstrating the subtle difference between the two.

What we're working on the basis is, we will bring this whole project via concept selection FEED to a sanction decision sometime in 2017, but we'll do it on the basis of the most certain reserves. So we want to be absolutely certain we've got a viable project with the minimum volumes, rather than volumes that are not entirely proven. We've also got, I'm showing here Malin. Actually, the work we've been doing in the months since we've taken over the E.ON portfolio and the people, is suggesting that actually Tolmount East goes over parts of what's called Malin here. We'll probably call that Tolmount Far East for the time being.

But the field is basically growing. We've got about 450 bcf in Tolmount; probably another 250 bcf recoverable in Tolmount East. We're still working on what the volumes will be in Tolmount Far East. We've got a number of export options so we can go take our gas to Cleeton that's Perenco's field; we can take it to Centrica's York. We can go directly to shore and there's two terminals there which you will have heard of, Easington and Dimlington, one Centrica and one Perenco operated. So we've got a variety of options which we'll cover in a second. The key aspect probably is the fact that it still delivers a high return even at today's gas prices.

I'm showing one of the development schematics so we're trying to internally we're bringing this to a concept selection at the end of this year with the aim of moving into FEED at the very beginning of 2017. We have the possibility of going unmanned at a subsea tie back to other fields. But, actually our preference is to create the possibility of a new hub here. The infrastructure, if we build a fixed platform albeit a very small one, it will give us a much easier opportunity to tie back Tolmount East which is what we're showing here; also Tolmount Far East; also, Artemis and then the other discoveries we might have in the area. The costs are more or less the same and this probably would end up being cheaper.

We're showing an export line to shore. As I say, it could go to Dimlington, could go to Easington and discussions are ongoing with those operators of those facilities. First gas will be in 2020 reasonable flow rates. This is all based only on the Tolmount main reserves, of course. Stepping back and zooming out of the whole of the gas basin, what we're showing here, these large rings are 30-kilometer radius. What we're trying to show, this is the tie-back distance to Tolmount, an operating facility we'll have over in the west and Babbage, which we operate in the east. In orange, you're seeing the various prospects that exist around the acreage we've got. Whilst fields like Artemis logically could easily be tied back to Perenco's Minerva, it may be commercially better for us just to tie it back to Tolmount. Those are the sort of work decisions and workflows that we've got going at the moment. As I say, it's all robust at less than 30p a therm. The focus for us on FEED in Tolmount will be on CapEx reduction, CapEx certainty and closing out the commercial agreement that we'd need to take it onshore, be it to Dimlington or Easington.

Moving further south to Sea Lion in the Falkland Islands, here we are midway through FEED. Already what we've been able to see is, been able to map out is reduced CapEx and reduced OpEx. But just as a reminder, so here's this is the Sea Lion picture you've all seen before. North is down that to the south west to the bottom of the picture. The plan is to develop the 200 million barrels that we're seeing in the north eastern part of Sea Lion and via an FPSO, as you can see. So far we've stripped out about 300 million barrels of CapEx to first oil, so down to about 1.5 billion to first oil. We've also taken about $10 a barrel off the OpEx as you can see here. It’s all the costs are coming down.

However, a project like this in a remote location of the Falklands does need a very careful review of project economics. And so whilst, at the same time, well, the internal team is focused on two things, getting the costs down and also working out with the Falkland Islanders how we can best make this an economic project. So that’s a piece of work that's ongoing. The team working on FEED are now in this building downstairs. They’re maximizing the value of the engineering work and preparing bid packages. And we’ll take a decision at the end of this year or the beginning of next as to whether we’re ready to submit those packages and seek bids or not.

Finally, a reminder that we are still undertaking some exploration, I wish I could show more material on this, but there’s a licensing round in Mexico, at the moment, with blocks all around our existing acreage. So you remember we got these blocks in the first licensing round in Mexico since 1938. And we’re very happy with them. Block 2 is in 20 meters of water in a basin that’s already had 9 billion barrels of oil found. Block 7 is in about 130 meters. And I’m showing here the line, which I’m not going to disclose the location, but it’s on one or our blocks. It shows the sort of prospects that we’re chasing. So we’re looking at sub-salt in proven reservoirs, with a proven source rock. The pink is the salt and the bluish colors are the reservoir horizon. And you’ve got four-way dip closures beneath the salt, and you’ve got up-dip fault traps against salt.

Elsewhere, I could have shown a line that’s got a, there’s another prospect that’s got a flat spot on it that’s conformal with structure. That might be the first thing we drill. And our plan, although they’re fully carried at the moment, so we’re not actually paying anything, our plan is to exercise our option to increase the 25%, because these are very good exploration plays, which work at low oil prices. And if we do that we’ll be in the position where we’ll be drilling at 25% equity starting in the middle of next year.

With that, I’ll pass over to Richard, for the finance section.

Richard Rose

Thanks, Robin. Good morning, everybody. I’ll now run you through the first half financial results, and I’ll give you an update on where we are with negotiations with our wider lending group. If I go just through the first half financial highlights. Despite the volatility and weakness in the oil price, I’m glad to announce we were profitable in the first half of the year, helped by a few non-cash items, which I’ll go through, and we delivered positive operating cash flow. As Tony said, we continue to focus on cost. And I’m pleased to say we continue to take cost out of the business, partially benefited by the lower dollar-sterling exchange rate.

As Solan is now approaching completion, we will see reduced CapEx commitments going forward, and that will help us, allow us, to get us to a position of generating free cash flow. At current oil prices, we expect that to happen during Q4 this year. As I say I’ll talk about our bank negotiations in a second, but it’s good to say we're making good progress with our wider lending group. It’s taking a bit of time. But we are, as I say, making good progress. If I turn to the cash flow first. Clearly, the weakness in oil price in the first half of the year has had an impact on our operating cash flow.

As a reminder, Brent average just below $40 a barrel for the first half of this year compared to the $58 a barrel in 2015 and that clearly had significant impact on our results. Also, impacting that was lower hedge volumes and lower realized prices for those hedges. The gas price obviously impacted as well. As you're aware, our Singapore gas contracts are linked to the oil price.

So, whilst operating cash flow was down 80% to $108 million in the period, we would highlight with increasing production in the second half of the year, thanks to E.ON and Solan, a stable cost base and higher oil prices, we anticipate we will generate around about $300 million of operating cash flow based on our current production guidance and oil prices.

So, in terms of CapEx in the first half of the year we spent $319 million. That was principally related to our Solan and Catcher developments. Our full-year guidance of $730 million is unchanged. However, if the sterling-dollar exchange rate stays at current levels we could see some upside to that number, and that may tweak down slightly in the second half of the year.

Net cash outflow in the period was $430 million and net debt finished at $2.6 billion, which was actually flat on our end Q1 position as we managed to defer a bunch of CapEx into the second half of the year. Turning to the P&L, I'm not planning to go through every single line item, I'm sure there may be some questions afterwards. I would just highlight two main line items.

A reduction in decommissioning estimate, $100 million, that reflects two things. Partially reduced decommissioning estimates on a couple of our assets but more fundamentally the impact of weaker dollar-sterling exchange rate on our decommissioning estimates, it's fairly mechanical, mark-to-market at June 30, but does highlight the exposure we have to weaker sterling.

The second point I'd note is the gain and loss on disposals line. Included in that $85 million is $106 million of negative goodwill related to the E.ON acquisition. This is essentially the excess of fair value we see under the assets over the consideration price we paid. And, I think vindicates our view at the time of the deal that we felt we'd got a bit of a bargain with E.ON's portfolio.

The gain we booked I think is conservative. We've used high decommissioning estimates in E.ON at the time of the deal and we've also got, I think, a modest valuation for Tolmount in there. But, certainly, it indicates, as I say that we felt we'd done a good deal at the time of the transaction. Bottom line those two items were the major contributors to delivering a profit in the first half of $170 million.

As Tony mentioned at the beginning, we continue to focus on reducing cost in the business. The chart in the top left, Tony mentioned in his opening speech, it just highlights the significant cost we've taken out, reducing our cash cost breakeven from $35 to around $25 this year. I stood up at the full-year results and said I saw the curve flattening in terms of our ability to continue to reduce costs. I would say I am glad to say that we are continuing to see cost reductions coming through. If I compare to where we were now with our budget, we are some $40 million under budget operating costs helped again by the weaker sterling exchange rate.

I may live to regret this again and say I do think the curve is flattening. But we do continue to see opportunities in the portfolio. Robin has mentioned we've been negotiating our FPSO contract in Vietnam. That's nearing completion and should save us around $7 million a year in OpEx costs.

Also, I'd highlight on E.ON, when we acquired E.ON we knew that there was a fairly bloated cost base in the organization. We've been getting after that significantly and we are starting to see the benefits of lower costs in the E.ON portfolio.

If we look at the bottom left, the table, half-year OpEx was $16.5 a barrel. But given the ramp-up in production and the savings we are guiding to $15 a barrel to $17 a barrel for the full year. I think with exchange rates where they are, we're likely to be into the lower half of that range. I would also just highlight the UK line. That again, I think demonstrates what we've been doing in the business in terms of reducing costs. Back in 2014 average of $37 a barrel; full year this year at $23 a barrel. We'll continue to look to try and manage that cost down. But, certainly, we view that as competitive against our peers.

If we look at the top-right graph, this is one you've seen us present before, but just highlights the significant reduction in CapEx we see going forward. With Solan complete, going forward our only major committed CapEx project at the moment is Catcher. Therefore, we'd expect CapEx to fall next year into the $350 million to $400 million range with a bit of variance on some infill programs like Chim Sao, etc. But we, absent any new significant projects we expect to maintain it at that level through 2018.

Turning to the balance sheet, net debt at the period end stood at $2.6 billion. As I say that was flat in the end of our Q1 position. We do expect net debt to peak probably at the end of this quarter at $2.9 billion, before starting to reduce depending on oil prices. Our main financial covenants and our debt arrangement is net debt to EBITDAX. On a rolling-12-month basis that came in at 5.2 times at June 30. Many of you are aware in our debt arrangements the covenant maximum is 4.75. As we've announced, we've as we've been going through negotiations with our lending groups, we've managed to get deferral with that testate.

Stepping back, at the time of the E.ON deal, it was clear that there was a risk we were going to breach covenants at the half-year. We're very proactive in reaching out to our lending group and starting negotiations on that. I'd make two points. First of all, we have a number of lending groups. We have four or five instruments each have multiple lenders behind them, the biggest of which is our RCF banks and we have some of those banks here in the audience. We have 25 there. I'd say we're dealing with probably 50 creditors in total.

The second thing I'd note is we weren't looking just to go out to revise financial covenants. We were looking at more fundamental maturity profiles of a term. I would say this is effectually akin to a full refinancing of the Group. Therefore, given the lending groups we're dealing with, it's clearly quite a complex process and also has a number of inter-creditor issues we have to deal with. However, the fact that it's taking time shouldn't detract from the fact that we have made significant progress to date. I think we have key alignment with our lending groups on some of the key principals. Revised maturity profile, we're looking to push right some of our early maturities.

I think we've got broad agreements on the shape of potential financial covenant amendments. We'll be offering security to our lenders. I think we are fairly unique amongst our peer groups in having an unsecured asset base and the fact that we're offering security will just really put us in line with the rest of the industry. We'll be offering enhanced economics. But crucially and I think this is a key point, we are looking to preserve our liquidity. In the negotiations we've had with lenders, we're not talking about reducing facility limits or sizes. As Tony's mentioned, we have cash and undrawn facilities around $800 million at June 30 and we have access to those facilities under agreements with our lenders.

Rolling forward, we, it's going to take time, but we expect to finalize full terms and implement revised amendments and agreements during the second half of this year. In parallel with that, as I say, we expect to start de-leveraging in Q4, potentially, modestly, at current oil prices, but that should accelerate as the oil price increases. Clearly, a priority for our business is to reduce debt, fee leverage, and, above all, try and return our key financial covenants down to investment-grade ratings of less than 3 times net debt EBITDAX.

So in summary, yes, it is taking a bit of time. But I’m absolutely confident we will get a solution in the near-term, and in due course. I’d just ask everybody to be a little bit patient while we finalize the negotiation. Thanks. Tony.

Tony Durrant

Thanks, Richard. I’ll just finish with something of a look forward. You’ve seen that we’ve increased production guidance for 2016. We’ve talked about production of over 90,000 barrels a day in recent weeks, and that’s before the new Solan well coming on stream. So, delivery capacity of over 100,000 barrels per day. And, of course, Catcher coming on stream towards the back end of next year. We’ll need to through the full budget process we’re just about to embark on for 2017. But we’re very confident that we’ll be increasing our production expectations by at least 10,000 barrels a day, per year, over the next couple of years.

Catcher is absolutely critical to Premier, safe and timely delivery of the Catcher project. It won’t come as a surprise that the Solan experience is still rather a bitter taste, and caused a lot of soul-searching in Premier. Premier, if you go back that far, previously has an extremely good record in delivering operated projects, going back to Anoa and Yetagun in the early 2000s, to Chim Sao and Gajah Baru the late 2000s, to Naga and Pelikan in Indonesia more recently. Solan, definitely, came as a shock. We analyzed the errors that we made in the Solan project planning. We’ve not repeated those in Catcher. And we won’t repeat them in any new projects that we sanction, either.

Catcher, as Robin described, is going extremely well, and we’re very confident that it will grow to be one of the strongest assets in our portfolio, and will come on stream in the fourth quarter of 2017. Beyond Catcher, I hope we’ve given a bit of a flavor for some of the newer projects. Those range, as we described, from infill opportunities, things like the Chim Sao infill drilling program for next year, which have very high rates of return, in most cases more than 50% IRRs, through Tolmount and, indeed, to Sea Lion. We will be very selective about which of those projects we take through the sanction gate. I think that is, actually, a process that the industry, as a whole, needs to be much more selective about going forward. The days of sanctioning every project in the portfolio, I think, are gone.

That’s not new to Premier. We have a history of selling assets at the predevelopment stage, think about Ca Rang Do in Vietnam, North Sumatra Block A or Vette in Norway. So we’ll continue to review the sale or partial sale option at the point of sanction, as we have done in the past. But there are some very promising projects in the portfolio now with good IRRs, even at low prices.

We will maintain a competitive cost base even if we see the oil price rising again. It's a lesson to be learnt, of course, from the last couple of years that maintaining that competitive cost base in a volatile commodity world is critical. We've set ourselves targets of around $10 OpEx for CapEx projects or $20 per barrel where we choose the lease option. That happens to fit with both Solan and Catcher. And overall, we can see $15 per barrel across the whole portfolio for a lengthy period of time and we intend to keep it that way.

Richard has given you a flavor for the discussions on debt reduction. From my point of view, it's very encouraging that the discussions we're having with the lending groups are based not just on what you might call a rundown scenario, but on truly an investment case. To be clear, the priority is debt reduction and a lot of the cash flows that will come from increased production and from lower costs will be directed at that debt reduction. But there are a number of investment projects and those are built into the discussions we're having with our lending groups.

The priority, Richard mentioned it, to get back the balance sheet into a position, which you would normally associate with investment grade type metrics. On our current model, at current forward curve, we're back to 3 times EBITDAX in the second half of 2018, and that's a good proxy for those metrics.

So in summary, growing production over a longer period of time, a competitive cost base. Both of those combining to increase free cash flow predominantly directed in the short term at debt reduction. But a portfolio of good IRR projects to invest as we go forward. I'll open it up to questions.

Malcolm?

Question-and-Answer Session

Q - Malcolm Graham-Wood

Malcolm Graham-Wood, Hydrocarbon Capital. The question I've got is, to start with, about Bagpuss a bit, because I've read a number of things in the press recently. First of all, it was heavy oil, then it wasn't heavy oil. I saw Robin saying it was a very big discovery, after which I wrote the last thing you want now is another big discovery. But in fact, given what you're saying about projects going to sanction and selling off things and it competing with, say, Sea Lion for capital, I just wonder if you could maybe Robin could clear the decks on how big it is, and how heavy it is, and where it's going to compete?

Tony Durrant

Yes, let me kick off and Robin can add. It is a heavy oil discovery; I don't think there's any doubt about that. It came in on prognosis, in terms of the reservoir. The geochemistry of the samples collected is still going on. There is post-drill analysis work still going on and that will tell us more about the flow properties in due course and it would be wrong to completely draw a line on it until we've done that work.

However, as you can imagine, in the current environment and given our particular circumstance, I personally don't see us dedicating more capital to a heavy oil project in the North Sea in the short term. We will wait for the post-drill analysis and then we'll also wait for an improvement in the environment. Robin?

Robin Allan

And I was going to say, Tony's turned into a geologist, I could add a little bit. It's drilled on the Halibut Horst, so it is a very large granite cord structure. So, of course, it's hotter when the granite's that close to the surface. We'd expected to find an increased geothermal gradient locally that we would hope would make the oil more mobile. There's been some discussion of this in the press. The oil doesn't appear to be as mobile as we'd hoped, but the analysis is ongoing. It would be, as Tony says, foolish really to say too much about it. There's a lot of oil in place, clearly, so that's fine. How easy it would be to get out would be a moot point and there will be a variety of opinions on that. But it was about the same temperature as the original Amoco well. So it wasn't hugely different, but it is a raised geothermal gradient over the granite horst and that was to be expected.

Tony Durrant

Nathan?

Nathan Piper

Thanks, good morning. Nathan Piper from RBC. Three quick questions if I may. First of all, on your production profile in the sense of sustainability of it, you've had high operating efficiency. Some of the reservoirs have produced better than expected and all the rest of it. Is there any concern that we're at a particularly high watermark just now, that lots of things have come together for once in your favor and that can't be repeated in the long term? Or are you taking steps to consolidate this good production performance?

Tony Durrant

No, I think the steps to consolidate are in the infill drilling programs essentially. Most of the areas in our portfolio have got infill drilling opportunities. I'm thinking of Chim Sao; I'm thinking of Wytch Farm; I'm thinking about Huntington; I'm thinking about the various additional gas plays in Indonesia in and around our existing Anoa production. Obviously, infill programs are largely discretionary. So the pace and the extent of those infill programs will be decisions that we'll make driven primarily by oil price. But those programs are generally, as I indicated, very positive IRRs.

On the assumption that we press the button on those programs, I would expect to see current levels of production being maintained by incremental reserves from infill drilling. Obviously, if we did nothing then we'll be into natural decline rates of probably, overall, about 10% a year.

Nathan Piper

Yes, that helps. And then just secondly on to Tolmount, you've given a lot more profile this morning, which is helpful. If you were to progress it as you outlined this morning, what would be the spending profile? Obviously, you're highlighting it's all about deleveraging and all the rest of it this morning, but you can't both grow and de-lever or it's a tricky one to pull off, unless the oil price gets an awful lot higher. So I'm just wondering if you were to actually sanction it and go ahead, will you have to spend significant money on it?

Tony Durrant

Yes. So, a likely sanction date, I think, is towards the end of 2017. That means the bulk of the spending would be in 2018-2019. Frankly, that fits well with the step-up in cash flow that we'd achieved after Catcher. One of the things that we're not planning on doing, including in the discussion with our lenders, is embarking upon new investment projects that would require substantial more funding in the 2017 timeframe. So, essentially, it would fit rather well with the reinvestment of some of the post-Catcher cash flows.

Nathan Piper

Maybe we end off with a quick one. The framework agreement around your refinancing that we can now call it, you talked about it happening in Q3. Is that still the timeframe? I know some of the guys are in the back of the room, so maybe you could agree it now, but yes, is Q3 the right timeframe or should we be even more patient than that?

Tony Durrant

I'm hesitating to put a date on it, otherwise some of the guys in the back of the room will probably get excited, but…

Richard Rose

But we haven’t got the lawyers in, so it might be. I think the end of Q3 is certainly still possible for an agreement on terms. There then will be quite a substantial timeframe for re-documentation and the full approval across the whole credit space. So, as I think we mentioned earlier, I wouldn’t expect completion of the full extent to the refinancing until year-end, but I would expect us to be in a position to tell the outside world substance of the terms sometime late September or shortly after.

Nathan Piper

Thank you.

Tony Durrant

Michael?

Michael Alsford

Thanks. This is Michael Alsford from Citi. So, I’ve got a couple of questions. So firstly, I just wanted to come to your point 5 on your summary slide around debt reduction. I just wanted to know what oil price you are using for 2018 to, that’s going to get you to that 3 times EBITDAX?

Tony Durrant

This particular one is based on roughly the forward curve, so $50/$60 the remainder of the year, $55/$60 in 2018.

Michael Alsford

Okay, great. And then just thinking about reinvestment, again, when you talk about your returns that you could potentially generate from your own sanction portfolio. I guess, if you look at that, you clearly have prioritized infills and maybe Tolmount. Sea Lion dropped to third. I suppose, when I look at that, it would suggest therefore that Sea Lion is now a much lower priority and, I guess, is there any concerns that from a government perspective in the Falklands that they would want you to accelerate rather than?

Tony Durrant

I wouldn’t put it like that, Michael, because any investment decision, of course, is not just based on IRR. IRR is important, but the magnitude and the strategic nature of a field of Sea Lion, the size of it, will come into the equation as well. So I don’t think it’s quite as simple as just picking the best IRR project, otherwise our future would be based on infill wells, which I don’t think is the case. Discussions with the Falkland Islands Government are in a pretty good state. You might have seen that they’ve extended the license period to 2020, so I don’t feel under any great pressure from either government or anywhere else to make an early decision on Sea Lion. I think they are perfectly grownup about the oil price, and we need to get project economics in shape before we move forward.

Michael Alsford

Thank you.

Tony Durrant

James?

James Hosie

Hi. This is James Hosie from Barclays. Just one on the debt refinancing, again, so wondering if you could help us just understand what the cost of the changes you’re looking for? B, is it simply just paying another arrangement fee or could it be more punitive amendments, such as materially higher interest rates, equity warrants or some sort of cash sweep or other restrictions on how you allocate capital?

Tony Durrant

It is Barclays you’re from, is it? Just to --

Richard Rose

Chinese world that you’re working in, I guess.

Tony Durrant

Do you want to answer that one?

Richard Rose

Look, I don’t think we want to get into specifics. Clearly, we’re going to expect to a coupon bump as part of the negotiations, but I think we’re in discussions with lenders about a whole series of terms. I don’t really particularly want to start going into details on specific items at this stage.

Tony Durrant

I think the other point to make on cost of debt is, I think, if I remember rightly, our cost of debt was 4% in the first half. And I’m not particularly fond of increasing my cost of debt, but that is a pretty favorable cost of debt from a historical perspective. So, if, as I would expect, there would be some increase in debt we’re still in historically attractive cost levels, as far as interest rates are concerned.

James Hosie

So, up a bit but not materially so?

Tony Durrant

Your words, James.

James Hosie

Thank you.

Tony Durrant

David?

David Mirzai

David Mirzai, Deutsche Bank. Firstly, you talked about the choice between growing and de-levering that you're having with your creditors at the moment. A couple of years ago there seemed to be a disagreement amongst some of your leading shareholders about whether you should grow or return cash to them. How do you find the alignment of your key shareholders is nowadays, given your current criterion and your onward program?

Tony Durrant

I think it's obvious that all stakeholders want to see the balance sheet repaired, and that certainly includes me. I think that is the priority, as we described. I don't sense that there is any resistance to reinvesting in good projects in the future but the first priority is to repair the balance sheet as we've described. I think that's obviously true of our lending groups. I think it's also true of our main equity shareholders.

David Mirzai

Secondly, just to Robin, if I may? Would you care to share some of your learnings from the Solan development and delays, and just give us some idea of where the cost savings, which you expect you to get in the next 12 months, are going to come from?

Robin Allan

So, on Solan, the sum of the learnings, it would be a very long session indeed. I think if there was one principle learning it would be that we shouldn't inherit someone else's project and we need to make sure that any project, going forward has been entirely done by our own people. So, if you look at something like Tolmount, for example, we could have simply taken where E.ON had got to, they were trying to push towards a concept selection decision actually in at the end of May or even June this year. We've pushed all that back while rework it all and we're taking costs of it and fundamental elements of redesign.

So, and that would be it in a nutshell. It would be a very long session to go through all the different bits of Solan. But the principle is that we need to do these projects fully ourselves and not inherit someone else's.

Tony Durrant

I agree. I think that if there's one highlight that I would draw, it's contractor selection. We made mistakes in Solan in that respect. We've not repeated those in Catcher. BW are probably our first choice when it comes to FPSO operator and the Keppel yard in Singapore probably the same in respect of Catcher. When we've made the choices for the feed contractors on Sea Lion, we've approached it in the same way.

Just the importance of contractor selection and getting the right team with the right capabilities would be the highlight.

Tony Durrant

They've lost their skills. They have not done oil and gas construction work as a group for some 20 years now. We've found ourselves on Solan having to get, despite 30% unemployment in Fife at the time having to import welders from Lithuania. You had a second half of the question there, David, I think.

David Mirzai

And future cost savings that Richard expects you to find in the next 12 months.

Richard Rose

As I said the curve is flattening, it's more difficult. And we've gone through virtually every contract in our portfolio and renegotiate it. We strip costs down where we can. Clearly maintenance, health and safety are ring fenced. So, I think if we're looking forward, FPSO renegotiations we've done that with Chim Sao. There maybe some opportunities on Huntington. There is obviously stripping costs out of E.ON's portfolio.

We've still said in the past and I still think the future is greater collaboration in the North Sea. It's a slow-going story. There's some social and cultural issues we need to get over. But if roll forward five years I think that's where we're going to see the next step change in savings, but that's going to take time. It's going to take a few years to work through. We'll certainly see it on the decommissioning; there's a willingness for operators to get together on decommissioning. We need to now try and do that on actual operations as well.

Tony Durrant

There are some more questions around in the middle here. Thomas?

Thomas Martin

Thomas Martin, Numis. Could I ask three? First one back on debt and pay down. When you get through this process, just to be absolutely clear, will there be a requirement to get major investment decisions approved, if you like, by the lending group before you undertake them?

Tony Durrant

Short answer, very likely. Depends on the definition of major, of course.

Thomas Martin

Okay. That is likely to introduce some extended time in the development, planning and sanction process, presumably.

Tony Durrant

I wouldn't expect that. Bear in mind that we've got to go through JV partner approval process, government's approval processes wherever the project is. I would expect any bank or bond holder approvals to be done in parallel with that.

Richard Rose

Even before we start this process we have a very regular dialog with our lending group. I expect that to continue for obvious reasons going forward. So, we'll flag any sanction decisions well in advance and obviously try and build that into the process.

Thomas Martin

And then two projects, specific one's if I can. First of all, Solan is it still planned to de-man that facility and if so, when and what will be the OpEx impact?

Tony Durrant

Yes, it is. Obviously reduction in OpEx or I think probably over time anyway, more likely the maintenance at the current level of OpEx per barrel for a longer period of time as production comes off its peak. I would think unmanning will be into 2017 before we achieve that. It's wrapped up also with our choice of operations and management and management contractor going forward which is another process we're embarked upon.

Robin Allan

Can I just add to that? The unmanning of platforms is a critical part of cost reduction, of course, throughout the North Sea, so Babbage we're moving to make that unmanned. It was designed as a platform that could be normally unmanned. For reasons best known to themselves E.ON never moved it to unmanned. We are now making that move and hope to have it unmanned at the end of the year. Tolmount, I didn't mention it actually, but that will be planned to be a normally unmanned platform, so in terms of the way forward on cost reduction, unmanning of offshore installations is a critical element.

Thomas Martin

And is it possible to give a guideline what dollar per barrel type of impact that tends to give you, or what portion [indiscernible].

Tony Durrant

Well, I'm not sure what dollar per barrel. I remember rightly the potential savings on Babbage that we've talked about are $6 million a year. I think I've got it right, gross.

Tony Durrant

Just to give you one indication.

Thomas Martin

A final one; on Catcher on the FPSO, I wasn't actually entirely clear. Have they entirely caught up with the FPSO delays?

Robin Allan

No, I'd say we're still probably a couple, well, we're on the schedule. We had hoped to be able to deliver first oil early on Catcher. And I think, probably, BW are still a couple of months behind where they would like to be.

Tony Durrant

I’d say BW have got a leaving the yard finance, which has boats leaving next May, and they’re a little behind that, but catching up rapidly, because of the number of people that Keppel are throwing at the program. We’ve always held, in contingency, a couple of months longer than that.

Thomas Martin

And would you absolutely not compress the pre-commissioning work to get it on-field earlier…

Tony Durrant

Been there, done that.

Thomas Martin

Fine, thank you.

Tony Durrant

James?

James Carmichael

James Carmichael, Peel Hunt. Just on Catcher, you mentioned that you’re not upgrading reserves yet, but I was just wondering what you need to see then to give you the confidence to do that, and as far as you can, when you might expect that?

Robin Allan

I think just more wells, that’s all. Obviously, everything we’ve had so far has been good or better than expected, so we’re just going to be cautious. We said at the outset that we were more conservative than others. We intend to remain that way really until sometime in 2017. So, our guys obviously are working up the field model as we go along, but if the wells carry on as they are, then we’ll be able to upgrade in due course. But we’re not ready to announce anything yet.

James Carmichael

Okay, thanks. And then, just secondly on hedging. It looks quite light in 2017, I think it’s 9% oil and about 20% gas. I’m just wondering how you’re thinking about that at the moment, and whether that’s forming part of your discussions with the lending group?

Richard Rose

Yes, it is forming discussions. I think the discussions are more around strategy than forced hedging. And I mean, the way that we’re looking at it is that cash flow breakeven next year depending on various factors in the $45/$50 range. We are at $46, at the moment. The forward curve is slightly above that. I think we’ll come out of the process with a hedging strategy that’s pretty similar to where we are at the moment, and we’ll look to progressively lock in that $50 above level. But, yes, it forming part of the discussions with the banking group, but I think the direction of travel is more around strategy than necessarily forced and locking in at the wrong price.

James Carmichael

Thanks.

Tony Durrant

One down the front here, Christine. Thanks.

Aaditya Chintalapati

Thank you. Aaditya from Pareto. Just a quick question. How much of the anticipated de-levering will likely come from asset sales and Solan monetization? Particularly given Solan is close to plateau, what are your thoughts on sale of your interests there?

Tony Durrant

There’s no firm plans in the plan, basically, for large scale asset disposals. Frankly the market is I think rather weak, at the moment, for large-scale asset proposals and I’m not proposing to sell assets at full prices. There are a whole series of non-core assets disposals, some of which we’ve already mentioned publicly, some of which will come out tidying up E.ON’s portfolio, but those are at the smaller end of the spectrum. We’ve been public about the situation on Sea Lion. We would like in time to bring in a partner for Sea Lion. That doesn’t mean to say that if someone comes up with the right number we won’t sell part of Solan or, indeed, any other asset, but major asset disposal is not on the agenda for the moment. Mark?

Mark Wilson

Yes. Mark Wilson from Jefferies. I’d just like to clarify something on the cash breakeven costs. You show $25 on the balance sheet, is that all in cash including interest. And how would you see that evolving into 2017?

Richard Rose

That's a good question. I would expect it to be, I wouldn't expect it to go up. I would expect it to be flat. The tax number's obviously, the slight equation in the oil price.

Tony Durrant

If you take OpEx at $15 a barrel, cash interest costs today are about $5 a barrel, that may go up as a result of the refinancing by a small amount. As Richard said, the variable amount is really the tax portion. At $25 a barrel, we're not paying much tax, but if we had higher oil prices then we would start to pay tax again.

Mark Wilson

Okay, great; thanks. Just two final things. Robin you spoke about bid package submissions for Sea Lion, are they a contracted bid package?

Robin Allan

Yes, the idea is to that we've got pretty good understanding of costs, but you only get firm prices when you go out with a detailed bid package that the contractors can bid against in a competitive market. The decision, of course, about when you go out with that, you don't go out with your bid packages until you have got line of sight of sanctionable project, because you can't hold those prices for a long enough period of time. That's a decision we're going to take at the end of this year or early next, is when to go out with the bid packages.

Mark Wilson

That's great. One final one, you spoke about not selling anything in these markets, but obviously the Catcher, the E.ON acquisition this year really was a step change that you're delivering. Are there any other possibilities like that out there?

Tony Durrant

I'd love that to be the case. I think it would be over ambitious to imagine that we could find another asset package with an enthusiastic seller with good production, with investment opportunities, with tax synergies, with cost synergies, all of which were present in E.ON. We'll keep looking. But I think we'll struggle to match the value per dollar that we've got with E.ON.

Last question in the middle there.

Unidentified Analyst

Actually this perfectly ties in with the last question, and it's probably for Rose. Could you tell us what was the book value of E.ON assets when you bought it? And the $100 million that you added now as a positive goodwill, is it based on the forward curve at June, 30th?

Richard Rose

I'm trying to remember what the book value was it's that long ago.

Tony Durrant

I'm not sure we ever knew because E.ON did take a write-down of their upstream portfolio as a whole but obviously involved in that was the disposal of the rest of the --.

Unidentified Analyst

So the $100 million that you reported today is additional values based on your acquisition cost?

Richard Rose

Yes, exactly. So it's the acquisition cost versus fair value. The oil price that we used is the same that we used from payment to year end. So, two years forward curve at the date, then $65 and then, I think, $80 long run beyond that. Just the other thing, on the negative goodwill, it doesn't include the benefit from the tax loss synergies we got. They come through the deferred tax line, so it's just purely on a calculated on a post-tax basis and any tax loss synergies, which obviously is part of the transaction they've been credited through the third pack. So the actual value uplift is greater than that $100 million we've necessarily booked through the goodwill line.

Unidentified Analyst

And just two more questions on the CapEx. You said the free cash flow end of Q4, what does that assume for CapEx?

Richard Rose

Well, the majority of the CapEx we've got will be spent during Q3. I will give you the breakdown between Q3 and Q4. But with Solan gone, it's just Catcher residual spending Q4. But I'll dig out the numbers.

Unidentified Analyst

Finally, on the $300 million of cash flow that you mentioned this year, is that pre-interest post tax in the full year?

Richard Rose

Correct, yes.

Unidentified Analyst

Full year?

Richard Rose

It's not the full year, it's the second half.

Unidentified Analyst

Second half pre interest?

Richard Rose

Yes, post-tax, pre interest yes.

Unidentified Analyst

Thank you.

Tony Durrant

Last question, then I think we should wrap up.

David Round

Thanks. Then I'll speak quickly. David Round from BMO. Last time we were here you talked a lot about mitigating actions around the covenant piece. As it's turned out you've managed to push those covenant tests further out, so you haven't necessarily needed them. But I'm curious why we didn't see much evidence of it because everything you were talking about sounded pretty achievable. So was it harder to implement than you thought or where you just very confident over the discussions with lenders? Then very briefly, you just said, I think Richard said earlier, that you'd used higher decom costs than E.ON had? Can you just tell me if anything's changed there?

Richard Rose

The first thing some of those mitigating actions haven't disappeared. We are in discussions with a couple of companies about prepay deals for instance to help manage liquidity. They haven't disappeared, but they're effectively been put on hold because quite rightly those counter parties are looking at our wider bank processes and saying they'd actually like to see that complete before moving ahead. So as I say, they haven't disappeared but some of them are kind of on the back burner and we may restart them depending on whether they get to with the financing. On the decom costs, no, I think we're just, inherently, we're just more conservative things like Ravensburn North, et cetera, where we've taken more conservative view on decom costs.

I think E.ON, we've got it in the release, E.ON I think had an estimate of about $450 million for the portfolio, where we're looking at $550 million, but hopefully over time, we'll pull those numbers out.

Tony Durrant

We'll wrap up and let people go if they wish to. Anybody that wants to stay very welcome, please revisit the Brasserie for another cup of coffee. Look forward to seeing you during the next few months, if not then February of next year.

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