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Edited Transcript of PMO.L earnings conference call or presentation 22-Aug-19 8:30am GMT

Half Year 2019 Premier Oil PLC Earnings Call

London Aug 29, 2019 (Thomson StreetEvents) -- Edited Transcript of Premier Oil PLC earnings conference call or presentation Thursday, August 22, 2019 at 8:30:00am GMT

TEXT version of Transcript

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Corporate Participants

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* Anthony R. C. Durrant

Premier Oil plc - CEO & Executive Director

* Richard Rose

Premier Oil plc - Finance Director & Executive Director

* Robin A. Allan

Premier Oil plc - Director of North Sea & Exploration and Executive Director

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Conference Call Participants

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* Al Stanton

RBC Capital Markets, LLC, Research Division - Analyst

* Amy Wong

UBS Investment Bank, Research Division - Head of European Oil Services, Executive Director & Analyst

* David Matthew Round

BMO Capital Markets Equity Research - Oil and Gas Research Analyst

* James Richard Hubbard

Numis Securities Limited, Research Division - Analyst

* Robin Alfred Haworth

Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst

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Presentation

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [1]

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Okay. Good morning, everyone. Thank you for those attending, and thank you also to those on the call for joining. I know some are actually joining from their holiday, so particular thanks to them.

Agenda for this morning is to review what has been another very good half year of operational and financial performance for Premier. In addition, we're going to spend, I think, a bit of extra time on 4 forward-looking projects, investments we're going to be making in our producing assets, the Tolmount area and new acreage that we've acquired and announced in the Andaman Sea and this morning in Alaska. All 4 of those we expect to drive significant value for the company over time.

Some highlights, first of all, from the first half. Strong cash flow, free cash flow generation, driving debt reduction. We have said for some time consistently that, that is our first and top corporate priority. That remains the case. It is strongly supported in the second half by our hedging program and therefore we have good confidence that, that free cash flow generation and debt reduction will continue into the second half.

Record first half production, 84,100 barrels a day, driven by very good performance on Catcher, and a very high operating efficiency. I'll talk a little bit about that and exactly how it's been achieved in due course. We completed, in the first half, the successful appraisal of the Zama asset in Mexico. We've announced P50 estimate of 810 million barrels for that asset, a world-class shallow water asset.

Our Tolmount project is on schedule. It's under budget. That's the construction project, Robin will talk a little more about that, and we are drilling ahead with our Tolmount East well as we speak.

New license capture. Our priority remains strict capital control, but we see an opportunity to add good quality acreage internationally. I personally think that some, anyway, of our oil industry colleagues are distracted. I think the North American companies are very focused on North America. I think some of the majors are focused on energy transition, and that's leaving an opportunity for people like ourselves to capture very good quality international acreage for the future. We'll talk more about that as we go through.

Looking ahead for the full year. Production, as I mentioned, 84,100 barrels a day in the first half. We previously updated our guidance to 75,000 to 80,000. We are obviously hoping we'll be very much at the top end of that guidance. Critical, I think is the current summer shutdown season. A lot of that going on in the North Sea, as we speak, subject to successfully emerging from those maintenance programs. I think we're in good shape for the full year and that will support free cash flow generation of over $300 million for the full year.

We don't often talk about HSE in these meetings. I think to some extent, that matter is taken as read. But I think there is a need in the current climate to be more open about safety and environmental performance. We'll talk about that. And we have had good performance in the first half of this year.

Reserve additions, we only formally, of course, update our reserves and resources at year-end. I can tell you that we're very optimistic about a further reserve upgrade on Catcher due to its continuing outperformance. We are already using a higher reserve number in our internal workings and that we expect to be confirmed at year-end.

And there are other areas of the portfolio as well. We had better-than-expected results from the drilling program at BIG-P. We've had a good infill well results, including one this week, actually, in Elgin-Franklin. We're drilling ahead in Tolmount East. All of those, I think, we expect to add to a good reserve and resource outcome when we come to the formal process at year-end.

On our predevelopments. We are evaluating farming interest on our Tuna field in Indonesia. We've formally confirmed that we are seeking a farm-in partner for Sea Lion. I don't think that will surprise anybody. That process is very much hand-in-hand with the process of seeking senior debt funding for the Sea Lion project. Most of you will be familiar that we submitted a package of information on Sea Lion about a month ago, and at that time we kicked off a farm down process sort of in parallel with that.

We've also announced this morning that we've already initiated a disposal proceed -- process for the sale of Zama. That is only Zama. We have other acreage in Mexico, and we're very keen on that acreage. So it's the sale of Zama, not the sale of our Mexico assets. Zama sale, again, we've not made any secret that we would take a decision on whether to stay with Zama after the appraisal program. The appraisal program has been very successful. We've upgraded resources. We know there is industry interest in Mexico and in particular in Zama. We'll be testing that over the coming months. I would expect further news on all those processes really by year-end.

I mentioned HSE a moment ago. I think the -- inside the oil industry, there has been a focus for a number of decades, really, on health, safety and environmental performance. But there is, of course, increased external stakeholder interest, in particular in emissions. We have already done what I think all companies will get to over time in terms of governance. We have a climate change committee in Premier. We have a new updated climate change policy, which is on our website. We are aligning ourselves with disclosure, even though we have been pretty good at disclosing in the past. And we've initiated a review of all our operations, actually, to identify further opportunities to reduce emissions. Good governance, I think everyone will get there in time. Just as important to me, though, is that, that's not just paying lip service, that we actually translate that into real actions. And I'd like to think we're somewhat ahead of the game in that. There are some very specific examples on this page, I would say, led by Catcher. Catcher is a new build FPSO, a high-spec FPSO. It has a modern -- very modern gas recovery, gas treatment and therefore a low GHG intensity level. We've taken actions recently on both our Huntington and our Solan fields to increase the percentage of the proportion of gas usage for power generation on those facilities. There are a whole string of activities in the areas of flaring, venting, waste management, diesel use reduction across all our fields, and we're making changes in the way in which we operate those fields.

Going forward, that will be translated into specific actions in designing new projects when we undertake whether it's greenfield new projects or right the way through to decommissioning projects. I think we're going to be very conscious going forward of the environmental impact of our actions.

As I mentioned, we've always disclosed GHG intensity. I'm sure -- I know we're going to be setting annual targets for those metrics going forward. To me, anyway, a combination of good governance, of full disclosure, but most importantly, perhaps, of getting our engineers focused on reducing emissions is the way forward in this area.

On that note, let me go back to the results and hand over to Richard.

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Richard Rose, Premier Oil plc - Finance Director & Executive Director [2]

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Thanks, Tony. Morning, everyone. Usual format, so I'll run you through the key highlights of the financial results for the first half of the year and a bit in terms of outlook. I'm glad to say strong operational performance, again, delivered and translated into a strong financial performance, which we'll touch on in a second. Record production, as Tony said, coupled with good cost control, higher realizations. We had 35% higher cash margins in the period. Part of that portfolio makes partly oil price and realizations meant that we delivered significant free cash flow in the period. And that obviously, in turn, reduced debt and improved our leverage ratios.

In terms of the financial priorities of the business, they remain, on the slide, they're unchanged. And the key for us is continuing to focus on debt reduction, looking to selectively invest in new projects, but doing that without compromising the strength of our balance sheet.

Turning to the financials in detail, it's the usual slide. It's very busy, so I'm not going go through every line item, just pick out a few key points. As we said, record production in the first half of the year. It was up 10% year-on-year, very driven by very higher price and efficiency across the asset base. I think Tony will touch on that a little bit later, but also we had a full year of plateau or full period of plateau rate production on Catcher. And that increase is despite completing disposals in the period, including Pakistan and Babbage at the end of 2018.

I would have so highlights our net realizations and despite the underlying Brent price being down period-on-period, we delivered a significantly higher realized oil price. That was due to mainly 2 factors. First is our hedging position. We had a significantly improved hedging position in the first half of this year, realizing about $69 a barrel for our Brent swaps. And the second, continue the theme I discussed at the full year results about strengthening differentials. So if we look and compare to where we were this point last year, we've seen about a $3.50 swing on the differentials we receive for our crude across the portfolio. I'm glad to say those strong differentials are continuing, especially on Catcher and Chim Sáo into the second half of the year.

So good cost control and also a bit of help on CapEx phasing meant we delivered net cash flow of over $180 million in the period against the cash outflow in the prior period. As Tony mentioned, we're on track to deliver north of $300 million of cash flow generation this year, in line with guidance. The slight reduction in the second half reflects the production phasing. As we mentioned, we're going through a fairly heavy maintenance period at the moment, which we're forecasting and a slightly higher level of CapEx phasing as the BIG-P project, completes in the second half of the year.

In terms of P&L, profits were up just over 20% at $120 million. Those numbers would have been even higher, but for the impact of IFRS 16. I'm not going to go into a lot of detail on that. There's a lot in the notes of the accounts and in summary on the slide here, but I'll just give a short summary. In essence, IFRS 16 is effectively where we're capitalizing our FPSO leases, which were operating leases before.

In terms of the P&L impact, it's really a reclassification out of OpEx into DD&A and finance costs. But given the profiles of the contracts, well, so over the life of those contracts, there'll be no net P&L impact. We are taking slightly higher cost earlier in those years, and that dragged our profits down by about $45 million in the first half of the year.

In terms of the cash flow, which I think is probably more important, it's just simply a reclassification out of operating cash flow into lease payments. But crucially, no impacts on free cash flow and no impact on our covenant calculations, which are effectively grandfathered in, in our finance arrangements.

So bottom line, net debt was down to $2.15 billion, which is the lowest level it's been since mid-2015. And just as important, our leverage ratio was down to 2.4, well in advance of our covenant leverage ratio of 3x in our financing arrangements.

Turning to see financial discipline, I mean we are seeing a much improved financial position, but we remain absolutely focused on capital discipline and cost control. As Tony will go through shortly, we have a number of upside opportunities in the portfolio. We'll selectively look -- we're looking to invest selectively in those, focusing on those high-return projects with short paybacks and generally operated where we can obviously control the timing and phasing of cash flows.

For large projects like Tolmount, I think we've demonstrated good commercial flexibility in reducing balance exposure through financing partnerships. We'll continue to look at those on a selective basis. On exploration, exploration remains a core part of strategy, so E&A activities will continue in the business. But again, we remain disciplined how much capital we allocate to that area.

So in terms of hard numbers, this year's guidance of $340 million remains unchanged. That's a mixture of abex, exploration and P&D CapEx, though we are trending slightly lower than that. But despite a high level of activity next year, and again, Robin and Tony will talk about this, we anticipate CapEx will be only around $400 million next year. We're going through the budget cycle, it may change, but that's our current expectation.

In terms of hedging, as Tony mentioned, we benefited from very good hedging cover in the first half of 2019. Average realized prices were $69 a barrel for swaps. I'm glad to say, that cover is extended in the second half of the year. Highlights, we've got about 4 million barrels hedged at $69 a barrel, which represents just over 40% for the second half, and we retain good cover in U.K. gas and Indonesian gas as well. And we're starting to increase our hedging exposure for 2020. We have reasonable cover, again, in all those product lines. And I would just highlight for both U.K. gas and Indonesia, we managed to extend out to the end of 2020 at favorable rates above current spot rates. So we'll continue to look to increase our hedging, if we see any spikes in prices.

Turning to debt and the balance sheet. As I said, net debt at the half year, $2.15 billion. We remain on track to deliver year-end net debt of around $2 billion or even less. Our covenant leverage ratio will continue to fall. At current oil prices, we should be down at about 2.3x at year-end. And on current share price, we're generating a free cash flow yield of over 40%, which I think probably says more about the share price than it does about the significant cash flow generation.

I've got a few graphs here, just stepping back. If you look to where we were in 2017, I'm sharing some of the numbers we shared with our lenders at that time. The reason I'm doing this is that we've significantly outperformed what we showed our lending group at the time of our last refinancing. In virtually every metric, production, CapEx, free cash flow, we've outperformed, showing very strong discipline. Why am I mentioning that? Well, we don't have any imminent debt maturities. May '21 is when debt matures, but we've been very proactive, and we're starting to engage with our lenders in terms of future refinancing. And obviously, our ability to show and demonstrate we've out delivered over those last 3 years should see us in good stead as we move forward with that.

So in summary, very good first half. Focusing on debt reduction, we've demonstrated a lot on the first half of the year, expect more in the second half of the year. Thanks.

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [3]

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Thanks, Richard. Some brief points on production activities. Star of the show is indeed Catcher. We've referred to that already. Forecast free cash flow from Catcher alone net of more than $500 million this year. We will, in all likelihood, achieve cash payback on Catcher in less than 2 years from first oil. The plateau rate production on Catcher at around 70,000 barrels a day is, first of all, higher. And we will extend the extent of that plateau about 18 months longer than originally envisaged at sanction, and that's without taking into account additional infill wells, Catcher North, Laverda, which we expect to drill in the summer of 2020. So obviously, extremely good performance from Catcher.

Not the only field that's outperforming, though. We are above budget for Huntington. We are above budget for Elgin-Franklin. I mentioned already good infill success from the first data from a new well this week, also Chim Sáo.

Singapore is -- because of the availability of cheap LNG supplies, taking less gas than we might have hoped for, but we're very much protected by a 90% take-or-pay in the Singapore gas contract. We will have BIG-P in Block A coming on stream in the fourth quarter. And that will give us a lot more deliverability should the Singapore buyer return to higher demand or indeed should any of the other suppliers into the Singapore contract reduce their supply going forward.

How is all this being achieved? Well, the driver really is top quartile, top-tier performance on operating efficiency or uptime. Some data here provided from the OGA, obviously, it applies to the U.K. North Sea activities. You can see on the top right there that operating efficiency in the North Sea has consistently increased over time. Very pleased that Premier on a 3-year basis, 2016 to '18, is at 80%, so exceeding the general performance in the U.K. North Sea, and our number of 95% in the first half of this year is obviously very significantly above general industry performance.

How has this been achieved? Well, I'm a great believer in just hard work. I think a lot is attributable to the hard work of our operations team, supported by our operations, technical head office people. I think we should give a nod to the operations, the O&M contractors we use in the North Sea who are also performing well. And indeed, where we are a non-operator to those companies that are operating our fields.

I think, also, it's appropriate to mention digitalization, a much used word, but we are seeing the benefits, I think, as an industry of more and more online, real-time data. I think that's particularly true for new fields such as Catcher. We're seeing the benefit of that on Catcher. For Tolmount, for example, we will have, as we've mentioned before, literally, a digital twin of Tolmount, which means that all that data can be instantaneously monitored onshore and if necessary, immediate actions taken. So I think we're a particular beneficiary with a high proportion of new production in our portfolio. I think combination of that additional data and being on the ball in terms of making critical maintenance decisions means that we and indeed the whole of North Sea should be able to significantly exceed the levels of operating efficiency achieved in the past.

In terms of new investments in our producing and our sanctioned developments, I talked in March about a lot of potential in infill and intervention programs to add to and prolong our production profile from that existing asset base. We've worked very hard in the last 6 months to translate that potential into real projects. Top half of the page here are a number of projects. I won't go through everyone that have turned into approved investments.

Bottom half projects that have matured during those 6 months, we haven't got final approval. Perhaps we haven't finished all the work, but we're moving those projects along at a pace. And beyond the list of projects on this page, there are still a lot -- a further longer list where we're still working up to see if they can be translated into economic and sensible projects. So a lot of work within the producing asset portfolio. We've put a similar profile up in March. You'll see the light blue area there, that's the product of the new projects awaiting approval. A lot more of those infill projects have now been translated into the base green colored profile. Overall, production maintained or even increased over quite a long period from just those projects. Remember, this takes no account of new developments such as Junea or Sea Lion or Zama, or anything from our exploration activities.

I think on the previous page, you may have seen the headline, $1.6 billion of NPV from those incremental projects and $650 million already in those 2 base profiles. So very valuable to us. Big part of that is the Greater Tolmount Area. I'll turn it over to Robin to talk about the specifics of Tolmount.

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Robin A. Allan, Premier Oil plc - Director of North Sea & Exploration and Executive Director [4]

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Thanks very much, Tony. So Tolmount, we have spoken about before, but it's -- to remind people, it's our low cost, partially tariff-funded development of 0.5 Tcf of gas just off the coast of Yorkshire. In barrel of oil equivalent terms, it's about the same size as Catcher, just to put it in sort of general framework. We engaged a series of tier 1 contractors to help us through this projects. So we have Rosetti in Italy who are doing the engineering and construction of the platform. Heerema will be doing the installation with their Sleipner crane setup. Saipem will be putting in place the pipeline. And the onshore terminal, Centrica's Easington terminal Jacobs Engineering are doing engineering to revamp that terminal to make it ready to take the Tolmount gas.

And of course, later next year, we'll be drilling the development wells using the Ensco 123 rig, and the project team has been working very well, working closely with our partners Dana, with Kellas who are the infrastructure partner and the Humber Gathering System. The whole project is on schedule. It's slightly under budget. And we'll just keep you updated during the course of the year. The [sale out in some of the jacket] will be about Easter time next year. So I'm sure at our results presentation we'll be saying a bit more about that. I'm showing some nice pictures. The chart here shows the hopeful contribution from Tolmount East. And there's a whole area east of Tolmount which we'll talk about now which lies, we believe, above the gas water contact in Tolmount itself.

So at Tolmount, we have the gas down too found in Tolmount. We've done a number of depth conversions and so on, and worked out where the gas water contact is from the pressure data in the Tolmount wells, mapped it around the area. And this whole area east of Tolmount, almost all of it is lying above the Tolmount known gas down, too. So we're expecting there to be reasonable volumes of gas in this area. Hopefully, we'll find them with this first appraisal well here in Tolmount East. If that works, of course, got a new 3D now, and I was looking at results earlier this week of the first stage processing, that's all looking good. We should therefore be able to track and map more gas, we believe, should exist at Tolmount Far East around Mongour. And of course, there's other upsides actually west of Tolmount and to the southeast of Tolmount. So we are expecting the gas prize here to grow over time, and we'll talk more about that I'm sure in the coming months. The results of Tolmount East, it spudded on the 8th of August. We're at 3,000 foot this morning. Top pay is about 9,760 feet subsea, and we're expecting results in October.

Turning to Mexico now and the Zama development. I mean since we got involved here, we spent a little under $60 million. And for that, we've got 4 wells, 400 meters of core, countless logs, tests and so on. And it's all gone to prove what we first hoped for when we saw the flat spot on seismic. So we got in the area because of 2 reasons. There's a fabulous source rock in the area, and there was a discontinuity in the form of the Mexican government opening up and allowing people to participate -- foreign investors to participate in the exploration of the area. So we've explored. We've now appraised. We've upgraded the reserves. So I mean the results of the appraisal well was -- wells was slightly better than we were expecting, and we're pleased about that. We've done a vast amount now of engineering as well as a group. So we're sitting there with indicative development shown here. Bioengineering,, which is a combination of Halliburton and GE. They basically have been doing engineering on behalf of the consortium. It looks as if the 2 platform solution is going to deliver the best result. The operator's planning to put the FDP in the first quarter next year, and the whole project is moving forward rather well. As I say, we haven't spent very much. And as Tony also said, we've initiated a sales process for the asset. Chances are, we will have the results of that before the end of this year. But it's been a fabulous project for us, and it's a great project for the people of Mexico.

Moving to a slide that really just reviewing our overall approach to exploration. I think we have talked about this to most of you before, but we don't spend a lot of money on exploration. We -- what we spend is spent quite frugally in under-explored emerging plays in proven basins. What that means really is we're simply looking for world-class source rocks and for some sort of discontinuity. So in the case of Mexico, it's because the country opened up. In the case of some like -- bit of Indonesia, we had access to a particular piece of seismic that other people didn't have that allowed us to see something that others haven't actually been able to properly assess.

So I think we should return, first of all, to remind ourselves of Mexico. We still continue in Mexico. So we have, as you know, signed up Block 30. It's the same principle, of course, as block 7 with the Zama. So we've got a recognizable flat spot on the seismic. Similar structure, so you've got a large fault caused salt core. Of course, we're showing a theoretical line here, but Zama is up here. We go through the Wahoo project and then down to Amoco, which has got over 1 billion in place to the south. So it's a fabulous looking thing here. I was looking at some of the seismic on that earlier this week as well with quite a huge 3D that's being processed. We expect to be drilling this late next year or the latest in sort of January 2021. That's looking really good. And there are other prospects, of course, on the block, co-builder and so on. And we've also got our hidden gems, the Burgos blocks. We're reprocessing some old seismic there at the moment. We've seen some flat spots there as well. Again, fabulous source rock, huge amounts of oil pass through our blocks and have been found onshore. And what we are chasing is -- will be flat spot identification in those blocks there. We have no commitment in terms of drilling as it happens there, but I very much expect us to take it forward to that phase.

Indonesia, as I said earlier, we got in here because we had access to a particular piece of seismic. We've acquired a new multiclient 3D, which you see in the blue outline. And looking at the early data from that, that again, still being processed, and I can't show that data today because I haven't got agreement to show you. But I know for a fact that the data is showing that the flat spots we saw on the 2D seismic are not just -- not only there, but the 3D data is making the whole thing look a heck of a lot better. So what we've got is multi-TCF gas potential sitting there and that's why, basically, you saw the announcement in July, we've deepened our interest in the area by adding equity in Andaman 1 and South Andaman with our partner Mubadala. So we're very extremely happy about that and look forward to saying more about that once we get that 3D data fully processed.

Turning finally then to Alaska. Today, we've announced our entry into Alaska. Now most of you already know about Alaska, a multibillion -- 28 billion found to date in the Prudhoe Bay, and then the discoveries to the west of it many, many years ago. So it's a massive oil province. And I'll just take a few moments just to sort of set the scene about what we're seeing on the map on the top right of this page. So you can see Prudhoe Bay. You can see a green line coming down from it. That line is the Dalton highway, so all year round road. Alongside it runs the Trans-Alaskan Pipeline that goes all the way to the Southern coast of Alaska for export. That's been running at -- originally at 2 million barrels a day, now only 0.5 million barrels a day, and is now an open access line. We'll talk a bit more about that in the context of our development, but we've been looking at Alaska for nearly 2 years now. And the reason we've been looking at it is, again, fantastic source rocks, well-known in the area, but things have started to change. So the original play in the north was in a deeper Jurassic and Triassic called Ellesmerian plays, mainly. That was the first phase of exploration in Alaska. A second phase has happened to the west. So the large green blob you can see on the west of that map, that's the Willow set of discoveries that Conoco have. That's about -- Conoco have announced it as being 450 million to 700 million barrels recoverable. And next to it, this other slice is the Pikka Horseshoe trend and that's something that Armstrong were one of the pioneers that now Oil Search, Eni, Repsol are all piling into this area. And that's got about 3.6 billion in place. And actually also it's just announced, some people have seen it going forward with 120,000 barrel a day development there. Now that play there is in the Cretaceous. That's a younger play, and it's in what's called top set sandstones, and we'll talk about that in a minute. But let's first of all talk a bit more about what we have done by way of a deal. So the deal we've done is shown here and included in our release today. We farmed in for a 60% interest to basically drill an appraisal well to an existing discovery. That gives us an opportunity to expand from there, which we'll talk about in a second. So we're very, very happy that we're working it. We do also have a little bit of an advantage. Three of our non-execs have actually ex-BP, 2 have a very strong and specific experience working in Alaska, and that has helped us in coming to understand what's -- how to operate in the area and what the potential benefits are.

Turning a bit to the geology. So I've talked already about the original target in the area being Jurassic and Triassic, and deep is what BP were going after with the well that's drilled right in the middle of the block that we farmed into. So they drilled this well in '91, found 77 meters of pay, never tested it. Wasn't what they were looking for, [take your] sandstones, not interested, didn't bother. So we're coming back to the same area. There's proven source rocks. There's a great source rock here called the HRZ. That's the source rock for the Willow and Horseshoe, multi billions of barrels in place. We're drilling the same thing that has already been drilled and testing it, which wasn't done before. You remember I mentioned earlier on, if you look at the map on the bottom left, about the top set sandstones, the Nanushuk sandstones, they're called actually the Willow and Peaker and Horseshoe. As these come off a shelf, they come down, form turbiditic sandstones. That's basically what we're drilling. They already exist. We know they exist because they've been drilled. We know they got oil in. We just don't know how it will flow, and that hasn't been flow tested in the area. So we've got a 3D data set here already. We've interpreted that in terms of the geobodies that exist in the same way as we looked at geobodies and talked to most of you before about the capture mapping. And we've determined there's about 1 billion barrels potentially in place here. So all we've got to do now is drill the well and test it. And that's in this what's called the Torok formation, stellar sandstones. You can see them here very clearly. There is another play. There's another play on the block as well, which is the Schrader Bluff, but we're not chasing that at the moment. We're simply chasing the sandstones that have already been discovered.

What Alaska gives us as a company, I think, is a great opportunity to make a very large amount of money. I mean we -- in terms of what would happen, we will drill the first well in January, February or so next year. If it finds the right amount of sand, we're going to test it. We will then, if that works, come back the next year, do a long reach well, test that. And if that works, we have a development. So we have optionality to drop out at any time or continue at any time or sell at any time. We also in terms of what the value to us is, I think you'll have seen, some of you, that All Search published, they think they'll get a 61% market share. We've looked at the same set of terms and worked out a slightly lower market share. But if you had a market share take for the contractor of, let's say 40%, then this is worth $4 a barrel. If you get 50%, it's worth a lot more. If you get the 60% that All Search think you can, by the way, they've structured their development and optimized it, you make a lot more money. And we are chasing here a net share of 150 million barrels of reserves.

And with that, I'll pass back to Tony.

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [5]

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Thanks, Robin. I think we'll be saying a lot more about Sea Lion later in the year. I mentioned already that we've submitted the package for study by senior debt providers and also formalized farm down process. The project team itself, I think, has spent much of the year optimizing the project. And in the course of doing so, we fixed, and that's reflected in the documentation, on a potential development of 250 million barrels. That's somewhat higher than that we previously talked about, 220 million or so before. We've added a southern drill center. Of course, there are an increased number of wells. That does increase the pre-first oil CapEx to about $1.8 billion, but it very much increases the NPV of the project. It reduces the cash breakeven. I think it also reinforces the value of the project at the P90 level, which is important for the lending -- for the lenders to the project. The project remains very robust from an economic point of view. You can see a figure there, peak annual free cash flow of more than $1.5 billion from the Sea Lion project. So we'll report back further on our progress in Sea Lion later in the year.

I think today, we've actually given out quite a lot of new data. Needless to say, there is a lot more data that supports that. And that can be made available to you over the coming days and weeks. I don't think we should lose the key takeaways from this morning's presentation, which I've summarized here. Be in no doubt that our highest corporate priority is still to utilize free cash flow to drive debt reduction. But I think you heard from Richard also that we feel our credit metrics are now back in line with our peers. It somewhat aggravates us to hear some of the phrases banded around about Premier being heavily debt laden and so on now that, that's the case, but we will continue to use our free cash flow to improve our balance sheet.

You heard from me that we still have multiple opportunities within our producing asset portfolio, a very good return on capital for those incremental projects. We've talked about the portfolio management processes to either crystallize development value without the CapEx implications or to reduce the size of those developments to fit the overall portfolio, and from Robin on the material new positions in several emerging exploration plays.

So I hope those are the main takeaway from today, and I'd like to open out to questions.

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Questions and Answers

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Robin Alfred Haworth, Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst [1]

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Robin Haworth from Stifel. Couple, if I may. Just on the -- you mentioned to start thinking about refinancing of your debt position. And just wondering, clearly, you're going to have to think about cash flow profiles. And so do we -- would we need to have a resolution to the Zama disposal process and Sea Lion farm down in order to get your -- to know enough about your cash flow needs in order for that to be done.

And then secondly, once those divestments, sell-downs were done, do you think you'd be happy with the shape of the portfolio? Are you still open to sort of large-scale M&A in relation to some of the packages of assets that have been available, probably no longer available, but would you be open to more and large deals?

And then final one, if I may. The way you drew the Tolmount East well looks pretty low risk. Can you just talk about what you're carrying as a chance of success on that well?

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [2]

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Let me start, Robin, and Richard, you might want to add. We continue to be interested in M&A. We talked about this at previous meetings, particularly in the U.K., there is logic in us continuing to grow our business in the U.K. because of our U.K. tax position. Don't think anything has changed there. And in particular, I think there is no evidence that we're not going to chase M&A for the sake of chasing M&A, and that remains the case. So we'll continue to look opportunistically. I'm not sure that I would put it as large-scale M&A to use your phrase.

In terms of timing, as I mentioned, I think there will be significant progress on both the Zama disposal and the process of putting a funding structure in place for Sea Lion during the second half of the year. Richard mentioned earlier that we'd already begun the process of talking to lenders about the refinancing, but I would emphasize the fact that refinancing isn't -- our existing debt doesn't mature until the middle of 2021. So I think we have some time there. And I think moving forward, those disposal processes will probably happen rather more quickly than the refinancing event.

Tolmount East, Robin, you want to comment?

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Robin A. Allan, Premier Oil plc - Director of North Sea & Exploration and Executive Director [3]

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Well, we've got the well spudded, so it would be a foolish person that gave a fair prediction because it either will work or it won't, so I'll give you 50-50. I think -- I feel very optimistic about it.

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Al Stanton, RBC Capital Markets, LLC, Research Division - Analyst [4]

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Al Stanton from RBC. I was just wondering how important growth is in the current era when people are kind of talking it down or at least the larger companies are. So you're talking today about sustainable plateau. If you had a reduced stake in Sea Lion, you could extend that further. So with respect to organic growth, is it discover something in harvest value. How important -- what's the strategy 5 years out?

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [5]

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I honestly think it's case-by-case because we have to look into the specifics of each asset as we have with Zama. Zama is a case in point for a number of reasons. We're exploring a sale rather than staying with the project right the way through. It's a non-operated asset. A disposal of Zama has no fundamental effects on our organization structure, for example, and we do think because of the industry interest in Mexico and in particular at Zama, that it may be the best way to capture value by a disposal. But I think that's all to do with the specific circumstances of Zama. We may take a different view on different assets.

I don't think we are standing here and saying, we have a firm strategy to either not go through development phases or definitely to go through development phases. I think we'll take it on a case-by-case basis. In the current environment, which you allude, I think it's clear that most of our stakeholders favor stronger balance sheets rather than riskier balance sheets. And that's probably biased us in favor of these disposal processes today.

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Al Stanton, RBC Capital Markets, LLC, Research Division - Analyst [6]

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And then just a follow-on, if I may, on Alaska. I mean what would the development profile look like that onshore? Is it a phased development?

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Robin A. Allan, Premier Oil plc - Director of North Sea & Exploration and Executive Director [7]

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So we (inaudible) we've got options, basically. So the way (inaudible) discovery well, if that's what it's going to be, it'll be drilled on an ice pad, you only put in gravel pads and so on and more expensive setup once you've actually got a commercial development. So in terms of how it all fits together, it's modular, so you build up a series of pads. So for example, our planned development scenario has sort of 14-odd wells per pad. You can have pads put close together. So for example, in the case of Oil Search's development, they've got 50 wells per pad, half injectors, half producers.

So we built it up in a modular way. Our development scenario that gave us the $4-plus a barrel, that was based on quite a conservative, taking the oil, not tapping it straight into the Trans-Alaskan Pipeline, but actually taking it all the way up to Pump Station 1 which is by Prudhoe Bay and then back down again.

So we've taken the sort of worst case development scenario, about $15 of development -- $15 million of development well and so on, water coming all the way from the sea and so on. So we've looked at, hammered it, really, in terms of development to make sure that we could get it to be commercially viable, and it's still flies easily through all our metrics.

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Richard Rose, Premier Oil plc - Finance Director & Executive Director [8]

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I think one of the advantages we see here for Alaska is that because it's not a typical offshore environment, we can build up the project. We will be the operator in the success case on a modular basis, and that allows us to control the rate and the totality of spend. David?

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David Matthew Round, BMO Capital Markets Equity Research - Oil and Gas Research Analyst [9]

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David Round, BMO. Focusing on Zama again, it looks like there's quite a lot of prospectivity still on the block. So really just interested in your thinking around a sale now versus staying in a bit longer drilling up the rest of the prospects. Follow-on to that, I guess is have those prospects been derisked by the Zama discovery? How do they rank versus everything else in the portfolio? And is there a way of ensuring on a sale that there's some sort of contingent element that you do get some exposure to them? And if -- on Zama, can I just ask, obviously, a big outstanding is the unitization. So how does that affect your thinking around timing?

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [10]

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Yes. I think the prospects are, of course, relatively derisked because of the success of the Zama program as a whole, including the appraisal. To be fair, I think they are still early stage prospects. The focus of the operator and our project people has been very much on the development. When you've got 800 million barrels in one corner of the block, you're bound, I think, to spend all your time thinking about the development of that first.

As far as the disposal process is concerned, we're obviously going to highlight the potential value of those other prospects during the process. And we'll see, I think, how that process goes in terms of capturing value. And what was your other question, David, sorry?

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David Matthew Round, BMO Capital Markets Equity Research - Oil and Gas Research Analyst [11]

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Just timing on unitization.

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [12]

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Yes. Unitization discussions are happening. I mean the operator is leaving now, of course, and are quite optimistic that they can be done relatively early in 2020 in time for FID during the course of 2020. But though -- but nothing to report today on those discussions. Any other questions? Amy?

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Amy Wong, UBS Investment Bank, Research Division - Head of European Oil Services, Executive Director & Analyst [13]

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Amy from UBS. Two questions from me, please. So firstly, just thinking about the -- going back to your M&A comments and kind of the events that have taken place in the industry the first half of this year and maybe packages that Premier wasn't successful at. Can you just talk about how would you characterize the M&A environment now? Any kind of things to think about to address the -- when you look forward to future M&A opportunities? And then my second question just relates to the Catcher area where you're flagging you'd expect to increase the reserves there, that's part of the year-end process. What were the some of the events that happened that helped you make that step to review that?

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [14]

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On the reserve position is essentially outperformance, reservoir, lower water cuts from the existing wells, good pressure data, et cetera, which come together in the form of dynamic model that's constantly updated by the team. And I would expect that process of reserve re-evaluation to continue every year going forward.

M&A, I think every situation is different. There are a number of situations well-reported in the press. Nothing is desperately live at the moment. I think our position is still the same as it was. We're interested in adding more barrels in the U.K. We would hope to get long-term assets in the U.K. We're not specialists in short-term mature assets. I don't think much has changed in what we would like to see.

Equally, we're not going to hand over the value of our tax losses to a seller because they do have value for Premier. They have value for Premier on a deferred basis. There's an opportunity to accelerate that value by adding more barrels, but it's a reason why we shouldn't hand over that value to someone else. Don't think our position has changed. Any more questions? Mr. Hubbard?

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James Richard Hubbard, Numis Securities Limited, Research Division - Analyst [15]

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James from Numis. The digitization, we heard a lot about that. It's quite hard to tie in the euphoria about it to actual metrics, but you're looking at, was it 95% uptime on Catcher or 99%, some very high number. Is that -- can you tie that directly to the digitization you mentioned? And I'm wondering, if so, how is that? Is that just able to do preemptive maintenance before things go wrong? I mean...

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [16]

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Yes. That's -- as I mentioned, I don't think it's only down to digitization. I think there's an awful lot of hard work, sweat, labor, thought, intelligence that goes into making the right decisions. But preventative maintenance is at the core of it, and that's definitely helped by having more instantly available data.

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James Richard Hubbard, Numis Securities Limited, Research Division - Analyst [17]

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And following on from that, you mentioned using it on Tolmount. So is the conclusion that to get a benefit from that, retroactively fitting it to your older fields is probably not worth it? It's got to be something that's engineered in from day 1. Does that make sense?

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [18]

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I think complete digital twins of older fields are not going to make any sense. I think there's still improvements that can be made to real-time data. But the real opportunity is with newer fields so that you can design in from day one. Robin?

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Robin A. Allan, Premier Oil plc - Director of North Sea & Exploration and Executive Director [19]

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No, that's exactly right. When we've been experimenting with retrofitting various bits of machinery on Balmoral with monitoring devices that allow us to see it back in the office how the engine is running and so on and so forth, it's proving very, very difficult to get bangs for your buck on that. Whereas what we've got on Catcher, so we designed effectively through a competition the actual Catcher FPSO, and we're involved in how we wanted it built. We ended up with a vessel that's, for example, a lot more expensive than one of our competitors' FPSOs on a daily basis. But what we have is a one that works really well. It's got a huge amount of data coming off that vessel onshore that's able to be analyzed. So newbuild is the way to go. And in Tolmount case, we'll have a digital twin. That will enable us to get ahead of the game forever and a day on Tolmount in the way we just can't do on an older field like Balmoral.

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Anthony R. C. Durrant, Premier Oil plc - CEO & Executive Director [20]

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I think we should call it a day at an hour, but we're obviously here if people have got one-to-one questions. Thank you again for attending. And look forward to further conversations in the coming days and weeks.