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Edited Transcript of PMO.L earnings conference call or presentation 5-Mar-20 9:30am GMT

London Apr 5, 2020 (Thomson StreetEvents) — Edited Transcript of Premier Oil PLC earnings conference call or presentation Thursday, March 5, 2020 at 9:30:00am GMT

* Anthony R. C. Durrant

* Robin A. Allan

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

Okay. Good morning, everybody, and thank you for attending our 2019 full year results presentation. Agenda for this morning, some highlights from myself. Richard will then report in detail on the financial results and provide an update on the progress of our proposed acquisitions and related funding. Stuart, our newly entitled Chief Operating Officer, will talk about our producing assets.

You will have seen from this morning’s announcement that Robin has decided to step down from the Board following the AGM in May. I’m very pleased to report, though, that we will be continuing to benefit from his experience, skills, wit and repartee, and that he will be staying on in Premier to lead our new net zero policy and related carbon-offsetting measures. So he will talk to them, particularly in the context of the update on our development projects. Dean Griffin, our Head of Exploration, is away in Alaska. More about that later. Tim Davies, our Group Exploration Manager, is going to talk to the upcoming exploration drilling program across the group.

So I think you’ll be familiar by now with the key elements of our 2019 performance, as reported again in our results this morning. I would highlight, as on the slide here, 4 recurring themes and 1 key output. Production, 78.4 kboepd in 2019. We’ve given guidance for this year of 70,000, 75,000 from our existing assets. We stand today at around 76.5 kboepd year-to-date, so good performance year-to-date. And we’ll update that guidance as we complete our proposed acquisitions later in the year.

The 2019 performance was driven by very high operating efficiency, 93%, which I think is remarkable really against the North Sea comparables of only a few years ago. I don’t often dwell on our HSE performance, but I do think that the HSE performance, which was very strong, is closely linked with high operating efficiency. And having not a single recordable injury at any of the Premier-operated sites during 2019 is something that we’re justifiably proud of.

Cost control. Cost control is a product really of our own, I think, efforts, vigilance, commercial negotiations and industry conditions. We see no immediate change in the industry conditions. $11 a barrel across the group for OpEx. $13 a barrel in the U.K. North Sea is, I think, a top performance on the cost side. And of course, that contributes very significantly to our ability to generate strong cash flow.

I think the performance of Catcher speaks for itself. In terms of our project management, Premier had over $0.5 billion of net cash flow from the Catcher project last year. Stuart will also talk about our very successful BIG-P projects in Indonesia. We had over 20 vessels, rigs, installations in very close proximity. So it was a project not without its complexities, and delighted that it was delivered on time and significantly below budget. A lot of focus on Tolmount at the moment. We’ll talk more about that later.

And more generally, I think it’s very pleasing that we’ve been the subject of quite a lot of incomings from the industry. I think that’s noticeably increased, where people are looking for Premier to act as an operator partner. I think that’s very encouraging. All of those themes, none of those are new to 2019, by the way, contribute to the free cash flow generation that we saw in 2019 of $327 million. And of course, we’ll talk about the profile of free cash flow generation for the medium term as well.

In the meantime, over to Richard for more details on 2019.

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

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Thanks, Tony. I’ll do the usual run through of the financials for 2019 and a bit of color on the near-term outlook. Apologies, I’ve got a bit of a croaky voice. I have got a bit of a cold. You’d be pleased to know I don’t have a temperature at the moment. It’s not trying to avoid you asking me questions at the end.

I’m pleased to report that the strong first half performance we saw last year was replicated in the second half of the year. Good production levels, improved net realizations and tight cost control, particularly OpEx and CapEx both coming below budget, and guidance contributed to, as Tony mentioned, record free cash flow in the year. It also meant our net debt reduced to less than $2 billion, which is the lowest level it’s been since 2014. Running for 2020, obviously, continued debt reduction remains the key focus. That will be enhanced once we’ve completed the acquisitions we’ve announced earlier in the year. And the association extension will put us in a good place to execute a future refinancing.

This is quite a busy slide, as usual, on the 2019 financials. I won’t go through all of it, but I’ll highlight the few key areas. In terms of production, production was down slightly year-on-year, reflecting some natural declines in the sale of our Pakistan business. But the underlying production performance from our key assets was strong, and we’d highlight Catcher in that regard. The second thing to note was our realized oil price. And despite the fact that Brent — the underlying Brent price was down year-on-year, we increased our post-hedged realized price. Two factors on that. We had better hedging realizations in the period compared to ’18.

And just continuing a theme, which I’ve discussed previously, we’ve got a chart here on the right that shows that our differentials to crude improved markedly in 2019, particularly on our Chim Sáo and Catcher crudes. And I’m pleased to say that, that has continued into 2020 as well despite the volatility we’ve seen in the underlying crude price. So strong production, good realizations, a better oil mix last year, tight cost control, CapEx coming in significantly under budget meant that, as Tony said, we delivered record free cash flow of $327 million.

In terms of the P&L, we delivered increased net profit, up $164 million, helped by some positive tax credits. That’s not a record, but it is the highest level we’ve seen since 2013 when we had $100 oil on the screen at the time. And so therefore, bottom line, net debt, as I said, coming in below $2 billion. Our covenant leverage ratio, 2.3x, both materially improved year-on-year.

Focus for us remains cost control and capital discipline despite the improving balance sheet. CapEx this year will be slightly higher, all in, at $470 million. But the focus of that, as you can see, is mainly on production and development operations. We have a number of drill strings running in the North Sea this year, Tolmount development drilling, infill drilling on Catcher and Solan. And those will provide a high-return, quick payback with production boost in Q4 through to 2021.

In terms of exploration, we have 2 wells drilling this year. The Charlie-1 well that started to spud in Alaska. We also have a well planned in Brazil in the second half of the year. And included in that spend of $90 million is some preparation work for 2 high-impact programs in Mexico and Indonesia in ’21.

Turning to abandonment. I’m glad to say we continue to only see modest costs, and we continue to defer COP dates on a lot of our assets. We’ve got a bit of a snippet here from Oil & Gas UK, which we would agree that we see decommissioning costs in general coming down and would expect that trend to continue in future years as operators get more experience, as more work increases in the North Sea.

Turning to our specific program in 2020. As you can see, our spend remains modest. It is slightly higher than previous guidance as we decided to take the opportunity to cease production on Huntington in Q2. However, Huntington is a prime example of one of those assets where we’ve deferred abandonment base on this for several years, and it’s an area Stuart will talk about in a couple of slides’ time.

We continue to employ an active hedging program to try and minimize the downside risk on commodity prices and commodity price volatility. In terms of oil production, first half of this year in our existing portfolio, we have about 40% hedged at $64 a barrel. I talked about this at the half year, but we are very proactive in hedging out a substantial portion of our Indonesian gas production. We were concerned about the impact of IMO 2020. I hate to say pricing has softened, but we’ve hedged on a post-tax basis almost 70% of our production. Our price is significantly higher than the current spot price.

Turning to U.K. gas. In 2020, we’re not significantly exposed both from our existing portfolio and when combined with the BP assets. But where we have exposure, we’ve hedged about 40% of our production at over 50p a therm. We would expect the outlook for gas price in 2020 to remain weak. We have a perfect storm at the moment, mild winter, surface LNG, cargo sloshing around the system and very high European storage levels. But we do have a more constructive outlook on U.K. gas, and this is reflected in the forward curve which increases to above 40p a therm going forward. That said, we are mindful that we will be seeing an increased exposure to U.K. gas with Tolmount coming on. So we’ve started to be proactive in putting floor and option contracts out into ’21 and ’22 to protect some of that downside.

Finally, key priority in the short term is to complete the announced acquisitions we disclosed in January. The deals — sorry, pardon me. For us, the deals remain compelling strategically despite the recent volatility in commodity prices. We’ve been very impressed with the performance of the fields. If you remember, the effective date on the BP assets is 1/1/19. Those assets outperformed our expectations in ’19 and continue to do so into early 2020, offsetting some of the commodity price weakness. So that means we’re still on track to execute and complete those deals without recourse to any additional debt financing, so fully funded by equity.

The upside we see on the deals is significant. As you know, we have over $4 billion of tax losses, and those tax synergies in the short to medium term will help generate cash flow, which will continue to see balance sheet deleveraging. And in the long term, we see operational synergies on the assets and development upside to create value for stakeholders.

In terms of the process itself, I’m pleased to say very strong creditor support at the recent creditor meeting. The court sanctioned hearing is due to take place on the 17th of March. It will last 2 to 3 days. And assuming we see a positive result from that, we’ll then formally roll into the equity raise. No decisions to be made on the split between placing and rights issue or that pricing, and we’ll also have discussions on that in the coming weeks.

So a major key focus for us, I would say, as a management team, we’ve had over 90 meetings since the deals were announced. And it’s clear we’ve got overwhelming positive support from shareholders, although, clearly, the deals will go through a shareholder vote at the appropriate time.

So in summary, I think from a financial perspective, a very good year in 2019. We over-delivered in terms of debt reduction and forecast free cash flow. That remains the priority in 2020. Yes, commodity prices are volatile. But we are a business, excluding corporate actions that will still generate free cash flow even down at current oil prices.

So with that, I’ll hand over to Stuart to talk through production operations.

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Stuart Wheaton, Premier Oil plc – Chief Technical Officer [3]

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Thanks, Richard. Good morning. So I have a few slides to go through the performance of our existing assets in 2019 and some plans for 2020 onwards, and also a slide talking to Andrew and the Shearwater asset as well in the proposed acquisition.

So on this first slide here, we’ve got a few highlights for 2019, which largely talk to themselves, but allows a little bit more detail in a few places. In the bottom left-hand chart, you can see an operating efficiency of our assets on trend for the last few years compared to a UKCS average from OGA data. Our operating efficiency here includes planned shutdowns as well. So to achieve 94% in our operated assets in 2019 was really quite outstanding. And in fact, there’s some real standout performers, and I’ll talk a bit more about Catcher in a minute, which spent 97% of its time in 2019 online, basically, at 66,000 barrels a day, which really was quite terrific.

There were also some other standouts like Chim Sáo at 95% and Solan at 90% as well and even higher in Indonesia as well on our gas assets. So really an outstanding performance. And clearly, going forward, trying to maintain that level, never seems to get any easier, but always being at 90% or over is where we’ll typically be aiming to be going forward.

A couple of other things to pick out in the bullet points here is, alongside the glamor of exploration and new projects, is making your existing assets work harder. So at the end of 2019, we’ve taken a 15 million BOE net increase in our reserves just on our existing assets by working them harder. So I’ll talk about infill drilling programs on Catcher. Extra well on Tolmount will be mentioned by Robin. And we’ve also got infill drilling program, quite a large one, proposed — well, in fact, planned for Indonesia next year.

As Tony mentioned, it wouldn’t really mean so much if we weren’t also safe in doing that. So the performance, safety-wise, particularly as our operations have got bigger, the scale of our projects and things, is really encouraging. Getting the safe and efficient operations working has really been a mantra of the company for the last 3 or 4 years. Similarly, a focus on greenhouse gases and the intensity, really a big part of our business and increasing going forward. And Robin Allan will talk about some significant changes to our approach for our developing projects, in particular, on greenhouse gases and climate change.

This plot on the bottom right-hand side, which is a trend of our greenhouse gas intensity, the amount of CO2 equivalent per BOE we produce, is on a positive trend here. And that reflects the efforts on emissions, reduced venting and flaring, energy efficiency, which many operators are doing, and we’re no different. It also reflects a modernization of our production with the start of assets such as Catcher. And we would expect this trend to continue, especially into 2021 with the start of Tolmount. So there’s a lot of focus in this area quite rightly.

If you wish to benchmark our performance, this would put us in second quartile versus most recent data available from IOGP. And going forward into 2021, very much our focus is to come into the top-quartile performance in terms of the amount of CO2 we’re emitting or the equivalent for the energy we are providing to the world. And in fact, on the next slide, you’ll see that Catcher is quite standout in this regard in being really one of the top in the U.K. So an important part of our business. And that’s really a sort of a 2019 sort of frame.

Looking forward on the outlooks, again, should be rising production, particularly into 2021; the start-up of Tolmount, which is still very much on track for the end of this year; and also the completion of the proposed deal on the BP assets as well, we’ll see a significant step up, and I’ll show that later. And last but not least, high-value, infrastructure-led opportunities such as Catcher North and Laverda. Tolmount East discovery last year, we’re already in the front-end work for Tolmount East with a view to sanction in the second half of this year and first gas a couple of years down the road. So quite a pace going on.

Let us turn to Catcher. So I’ll provide quite a bit of sort of overview of Catcher, clearly very important to us. On a typical day, it’s 40% of our net production. It was mentioned in our notes previously about the cash payback achieved in October of last year after just a bit less than 2 years of production. I mentioned the high operational efficiency, which is a reflection of the teamwork with BW Offshore, particularly on the FPSO, as you see here.

Today’s typical production is still around 66,000 barrels a day of oil, 2,000 to 3,000 barrels a day of gas export, and we’re currently producing at around 25% to 30% water cut. So typically, that’s around 25,000 barrels a day of water production as well. We’re also injecting about 100,000 barrels a day of seawater and that produced water back into the reservoir to maintain production.

Cumulative production from Catcher is now about 41 million barrels gross oil, and that’s in just over 2 years. And in fact, it’s useful to compare that back to when the project was sanctioned. When the project was sanctioned, we would have expected to have produced — our forecast then was around about 33 million barrels. So we’re of the order of 25% ahead of where we thought we would be. And that’s really a reflection of the reservoir performance, the wells, the reliability and that uptime of the vessel.

And that then has become reflected in our assessment of the reserves, as you see on the chart here. We took an addition at the end of 2019 of the order of 10 million barrels gross. And again, going back to when we sanctioned the project, the project was sanctioned with 88 million barrels of oil gross in mind. We now stand at 104 million barrels. And if you’re adding Catcher North and Laverda, that will take you up to the order of about 108 million barrels, so again, of the order of 20-odd percent increase so far.

Looking at this chart on the bottom left-hand side here, you can also see what we’ve been doing on production rates on the vessel as well. So when sanctioned, around about 50,000 barrels a day plateau was forecast. Because of the positive drilling results and the performance of the vessel by the time of first oil, we already plan to operate against the nameplate of 60,000 barrels a day. Because of the continued performance of the reservoirs, we then took that up to 66,000 barrels a day in agreement with BW Offshore. And in the second quarter of this year, we plan a trial to take it up to the order of 70,000 to 72,000 barrels a day. There are some constraints on the vessel, and this trial intends to go and find them, okay, in a controlled fashion in coming months. Okay? But notwithstanding that, we would expect the 66,000 barrels a day plateau rate to essentially run to the end of this year and then decline to set in after that.

We do have plans that Tony and others have mentioned for infill wells, and those start with drilling in May of this year, and then additions from our Varadero infill well. And Catcher North/Laverda should be in the bag by the end of the year and connected up to the vessel. Catcher North/Laverda production, you won’t really see this year, but you would see from early 2021.

Looking further ahead, we’ve got a couple of points here as well on the outlook. Because of the performance of the reservoir and our confidence in the investments here, we’re already looking at coming back to drill more wells next year as well. So 3 wells this year: Varadero, Catcher North, Laverda. And inside the joint venture at the moment, we’re looking at adding a further 2 wells at Burgman next year as well. So confident that we can come and add extra production and essentially moderate the decline of the field in its third or fourth year of production.

An exciting prospect next — or this year, I should say, for Catcher is a first for Premier to acquire 4D seismic. So this is like a time-lapse 4D to look at how the oil, water and gas has moved in the fields since it started producing. So that will enable us to calibrate all of our models and start looking for further infill opportunities and raising of reserves.

So finally, on Catcher, just to say, I mean, clearly, the performance has been strong to date, and we’re already engaging in the joint venture and with BW Offshore about the prospect of extending the contract term on the vessel beyond the initial 7 years, which would end at the end of 2024, which, frankly, isn’t actually that far away when you think about it.

Looking at our other production here in the U.K. We’ve got a selection of a couple of key assets to talk about. The non-operated share at Elgin Franklin may be modest, but it’s important. It’s there. It’s bedrock to our production here in the U.K. and should continue well out into the 2030s with various infill wells and well interventions.

Then we come to Solan, and here’s a picture of the Solan platform, West of Shetland, with its very friendly free-fall lifeboat. It’s quite a ride when you go in one of those, when you’ve done it in training, I’d like to point out. On Solan, again, high operational performance in 2019, safe operations. In fact, there’s been no recordable incidents on Solan for 4 years. It’s really that operational performance and understanding of what Solan is today that’s encouraged us to invest in a new well there this year. So the P3 well, we expect to spud later this month, early April, with a target to be online by the end of Q3.

Now a Solan well will initially produce around about 10,000 barrels a day, and that’s what we expect here. So it will be a significant boost to the production there. And again, the incremental reserves, 3 million or 4 million barrels, extension of the field life as well, it’s an incremental story at Solan these days. It will give us the opportunity as well to stop burning diesel on board and go back to being fuel gas-powered as well, which will be beneficial. If the well works out as we expect, we already have some plans to think about coming back next year for a further well on Solan yet again, which would be around a water injector. So really, for Solan, after what was a difficult project for us in the past, I think it’s fair to say Solan has come a long way due to the dedicated efforts of the team that’s been involved there.

Richard mentioned the Huntington asset, 100% operated by us with the leased Voyageur Spirit FPSO on board. We’ve got a plot up here of what has happened at Huntington since we acquired the E.ON U.K. share and the operatorship in 2016. You can see the E.ON base sales case and then the actual production that’s been achieved since. So this is the tale of taking over an asset from the previous operator and having a different approach. So essentially, we’ve added 2 years of further production as well as raise production during that period and the recovery.

So it’s a good example of the type of approach that maybe a different operator with a different set of eyes would bring to an asset, different well management, different reservoir management as well as extending the lease of the FPSO by 2 1-year extensions as well at lower cost in agreement with TK. But it has come to its end of commercial life now. Production is down at around about 3,000 barrels a day. We’ve reduced the costs to as low as credibly as possible. So we took the decision to cease production at the end of this month. So I’m sure you’ll be seeing some pictures of the FPSO coming into port at some point in Q2 of this year. And then thereafter, we’ll be looking at the decommissioning of the subsea infrastructure in the wells over the following 5 years, as was planned.

Let’s talk briefly about the BP U.K. assets proposed for acquisition this year and what has been happening at Andrew and Shearwater. Since the announcement, the production performance of the assets has been very much in line with expectations, and I’m sure you’ll be reading the Competent Person’s Report avidly in the coming weeks and months. You’ll see very close agreement with what was expected. In fact, production most recently has been actually above the levels in there. So this would be an addition of about 23,500 to 24,000 BOEs a day net BP coming into Premier during this year. And this pro forma production plot you see here, which goes back to the effective date of 1st of January 2019, actually also includes the extra 25% of Tolmount as well, which would largely come in, in 2021 as well. So you would be seeing a 40% to 45% uplift in our U.K. production with completion of that purchase.

There’s a few other notes on here about Andrew, about emissions and OpEx and your — the eagle-eyed will notice what a good fit it is with our existing U.K. portfolio, similar types of cost levels, similar types of emissions levels as well. We should report that the transition and integration work between BP and Premier is progressing well since the start of the year in all disciplines. This includes our involvement in some significant CapEx decisions for Andrew as well, which I’ll talk about a bit more in a minute. And we’ve also already been a frequent visitor offshore in Andrew as we engage with the offshore crew and deal with the personnel transfer issues, too.

So a confident acquirer of both these assets, though, must also see the potential in the future. And there are a few notes on here about the Andrew Lower Cretaceous project as well, which Robin will expand on a little bit further. But in summary, we definitely see the potential to extend the remaining commercial life of Andrew out to 2028 and onwards and also with Shearwater, which I’ll talk about in a moment. In fact, at Andrew, this year, we would expect some well intervention work on one of the subsea satellite wells to shut off water to continue to raise production and also progression and sanction decision on the Lower Cretaceous project in the second half of this year.

It’s worth really saying about the Lower Cretaceous that it’s actually already online through a platform well and has been for 2 years, which is a really effective way to calibrate your expectations on the project before you commit to something of the order of $100 million, $120 million net to us. So the front-end engineering work at the Lower Cretaceous project is going on at the moment, which we fully support, with the sanction decision to be made in the second half of this year.

Not forgetting Shearwater, the non-operated share there, that asset is really going through quite a transformational year with Shell undertaking extensive works to set it up for the future as an updated hub. So there are plans in the future built into our expectations of Shearwater, including infill wells on the field itself, at least a minimum of 3, and also key tiebacks. Several of you will be well aware that Shearwater is due to receive the hydrocarbons from Arran and Columbus in 2021. And then the prospect is out there for the sanctioned decision of Jackdaw as well later this year, early next year. A final little footnote on this slide is to note that the partner preemption rights for Shearwater expired in the last few weeks as well. So the other parties, they have decided not to join into the deal. Okay.

And the final slide for me to talk about Southeast Asia, a very important part of our business and has been for quite a few years now. I’m actually going to start with Vietnam, the Chim Sáo asset shown here in a few bullet points, again, a very, very solid year, meeting its budgets, its cost control expectations in really all sort of dimensions. Richard mentioned the premium where we’ve received the type of crude that is Chim Sáo, very important as well. I think the final thing to say about Chim Sáo is drilling hasn’t stopped there. And in fact, we have a field development plan. It’s sort of increment, in with the Vietnamese government to add 2 infill wells in 2021, and we’re waiting for final approval of that.

So turning to Indonesia, our long-term gas asset there in the Natuna Sea. Again, production in 2019 was pretty much in line with budget. In the middle of the year, actually, Singapore gas demand was quite low due to the sort of spot market LNG prices. But during the sort of later part of the year, there was a convergence on the prices. And you can see what our production trends has been as we’ve come into the end of the year and has continued since.

So looking forward, what will be happening there? We’ve got various other sort of work campaigns coming, including infill wells and reserves upgrades related to them. I need to sort of just give you a little bit more detail about that. So in 2021, we have a 5-well infill drilling program and work-over plan on all the various fields. So again, this is an extra 100 Bcf gross of gas or thereabouts which will be further developed. Really competitive prices, we’re around about $5 a BOE. So this is really sort of great incremental value addition on our existing assets. Combine that with some recompression projects, and we expect Natuna Sea Block A essentially to have a flat production profile for the next 3 years. We’re working the asset really quite hard. And again, if you add in the performance of the BIG-P project, which I’ll talk about shortly, it’s really been quite an impressive story in recent years.

Taking a look a little bit closer at Bison, Iguana, Gajah Puteri, the BIG-P project as we call it for short. It’s worth spending a little bit of time to give you a few ideas about what was achieved there. Just as a reminder, it was a 3-field subsea tieback project, but it had a very interesting geography about how it connected into all the platforms. It really was quite innovative as to who was connected to who and who controlled who. So the HSE performance of the project was excellent. It delivered its first gas, as planned, in the second half of 2019, not without its challenges, but those were overcome. It was mentioned about how the budget performance of the project went. Our original internal budget was around $320 million. We expect to come in around 25% underneath that. And that really reflects the fact that the project team didn’t have to use any allowances or contingencies during the project. Some might call that somewhat lucky, but also others might call it just decent project management as well.

So really a stellar performance. And the early production from those fields, you can see the impact. It means we’re supplying our extra sort of demands from Singapore with relative fees using the new wells. In fact, the new wells add up to about 94 million standard cubic foot a day gross production addition on Natuna Sea, which is really quite a difference. That’s about a 30% boost over what was there before. And the early production performance is very much supportive of the reserves level that we expected. In fact, when we drilled the Bison and Iguana wells, we intersected some gas-bearing sands, which was a very — extra gas-bearing sands, which was a very welcome surprise, which we will add their production later in field life.

So just coming to some conclusions on Indonesia. I think it will also link to what Tim Davies has to say about exploration in the Andaman Sea and also Robin about Natuna discovery appraisal. There’s really quite a growing story for Premier Indonesia, underpinned by the Natuna Sea Block A performance. And clearly, we’re in a good address there for supply of gas to various markets as well.

So finally, I will hand over to Robin to talk about our development projects, primarily around Tolmount and initially also about what’s happening with respect to carbon neutrality and climate change.

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

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Thank you very much, Stuart. All of us in this room, obviously, are concerned about climate change. And we all know that renewables, such as wind and solar, play an important role going forward. But alone, they don’t solve the energy needs for every geography. And given that oil and gas is going to be part of the energy mix for a very, very long time, each of us, I think, as individuals and corporates, has to find ways to mitigate the negative effects of our own footprint.

And at Premier, we’ve been looking at what we’ve been doing in terms of our emissions for a long time, actually been reporting and recording it for 10 years now. The main thing has been to focus on understanding what we’re emitting and doing what we can to minimize those emissions and looking everywhere for ways to reduce our footprint. One of the first things we did was in Indonesia. Perhaps a simple example that’s amazing how few companies are doing this, we found that our supply vessels were — and standby vessels were using up an incredible amount of fuel. Fuel means emissions. So we put in place a mooring buoy, which the sea is shallow enough to do there, and we had a massive reduction in our emissions and, of course, a huge reduction in the use of diesel. So it works on both levels.

What has been clear in recent years is the scale of the climate change challenges become clearer, and we’ve recognized the need to further improve our performance. Yes, the world needs our oil and gas, but it’s going to demand that we reduce our footprint to net zero, and we can and we must achieve that outcome.

On this page, we’ve set out some clear and I hope completely unambiguous targets. We put them under 2 banners: Low Carbon by Design and Carbon Neutral by Commitment. And what do we mean by that? Well, Low Carbon by Design, we have a work in place, not just to design our facilities, but to manage them, and all the efforts that go into manage them to consistently evaluate where our emissions are coming from and what we can do to reduce that. We’ve got an emissions hopper. So we put in all of our possible projects that we have to look at how we can actually reduce the emissions. So it’s different to the development hopper, different to the exploration hopper. It’s purely looking at all our emissions, what can we do about reducing them and how can we deploy the best available technology.

I mean it’s the work of our staff around the world, of course, that’s actually paying off dividends in this regard because they basically have been very diligent in tackling that topic, very committed to reducing the emissions. And it’s their work that’s enabled us to score a B with the Carbon Disclosure Project. They’re a group that requests information on climate risks and low-carbon opportunities for the world’s largest companies. They’ve got 525 institutional investors with $96 trillion of assets. So we’re very happy that our work is being recognized.

What do we mean then by Carbon Neutral by Commitment? Well, to the extent that we can’t reduce our emissions to net zero in themselves, we will ensure that we fund nature-based offsetting, principally forestry, in our own geographies to make sure that the net is carbon neutral. And that’s what we’re going to do. We’ll balance the quantity of carbon-capturing opportunities. So in the case of something like Tolmount, which I’ll talk about in a minute, we’ll be doing that in U.K. forestry projects.

So today, we’re going further than just what we’re doing in terms of Low Carbon by Design. But in the Carbon Neutral by Commitment, we’re committing that all of our future operated developments will be carbon neutral for Scopes 1 and 2. We’re further committing that all of our activities will be — operating activities will be 65-or-more percent net zero by 2025, so it’s a near-term target, and 100% net zero by 2030. So we are determined to put measurable, proper commitments out there, and our teams are absolutely committed to working towards this.

Actually, the feedback from the people around in the Premier sort of world has been incredibly positive. And we think that underlines our commitment as a company to become a carbon-neutral enterprise, meeting the demand for energy to be delivered in a carbon-neutral manner. We look forward to continuing on this path, and we’re hoping to become a bit of an advocate for our industry. We’d like other people to adopt our forward-leaning approach. And other oil companies, I hope, will take note and do something about their emissions in the same way as we have been and will continue to do.

Turning then to Tolmount. Tolmount is a Low Carbon by Design project. So from the outset, we looked at how we’d be able to design the whole project to be low carbon. So it’s not normally attended, not normally attended platforms, so there’s no people on board. There’s very few boats visiting it. There’s no — although you can land a helicopter, not planning to have regular helicopter visits. We’re running it on micro-gas turbines. The net carbon footprint of this field when it’s at peak production is going to be about 1,500 tons of carbon a year. That is incredibly small compared to numerous other fields in the North Sea, in particular, but all around the world. It’s a very, very low footprint. That’s about 300 cars’ worth.

To give you an idea of forestry, 2.5 acres of trees is about a ton of carbon a year, so — in terms of carbon capture. So we are going further than that. We’re having discussions already with the nearby wind farm owners to take power from them. So it would be even lower, I think, in the future once we’re able to do that with the Ørsted team.

So it’s on track. What you’re seeing on the picture here is the jacket and top sides in the yard at Ravenna. The jacket is about 2,500 tons of steel. The top side is about 2,300. There’s 100 kilometers of cable in there. It’s complicated. Like all these plants, it’s designed to be operated remotely, so there’s extra electronics and so on in there. The load-out onto a Heerema barge will take place on or about the 6th of April, and it will then sail away at the — towards the end of April. It’s 3,200 miles to the North Sea. It will be towed there by tugs at about 6.5 kilometers an hour.

The platform itself, as I think you know, is capable of managing 300 million cubic feet a day. Development drilling starts in June. It’s not an easy area for drilling. There’s a listric faulting. There’s some high-pressure zones in the Zechstein. We’ll be using managed pressure drilling to do that, so reasonably up-to-date new technologies. We’ll batch hole the top holes in June and July and then start completing wells thereafter. We’ve also got our sights on a fifth Tolmount well, which we think will not just bring forward production extending the plateau but also add extra reserves to the project. The pipe lay will be in the middle of the year, middle of the summer. The onshore Easington works are progressing. First gas targeted at year-end, about 20,000, 25,000 net on plateau to the group. So we’re very pleased with the progress we are making there.

Turning now to the growth projects. I mean what we’re not talking about here actually are some of the projects that Stuart mentioned before, the Anoa, Chim Sáo, Elgin Franklin, Catcher infills, all those sort of things. We’re just talking about some of the larger projects. And again, we’re designing these to be Low Carbon by Design and Carbon Neutral by Commitment. So Tolmount East which we found, as you know, last year, will be tied back to Tolmount itself. So it will derive power from Tolmount, which is to say, at the outset, will be these very efficient micro-gas turbines. It will end later. We plan to move it to wind power.

So FEED studies has been underway. We’ve been evaluating both the subsea and the platform concepts. Subsea offers the lowest capital cost, lowest power consumption, least materials, lowest fixed operating costs. The platform offers more flexibility to intervene in the wells. It’s got a commonality with Tolmount and the promise of higher operating efficiency. So those studies are going on. There’s the final seismic results coming in that will better inform that final decision. And our plan, as I say, is to take it to a final investment decision later this year.

Stuart touched earlier on the Andrew Lower Cretaceous. Again, it will be a 2-well subsea tieback, both wells with a single frac. There’s a number of different targets that we can go for on that field. There’s about 400 Bcf of gas to be tapped. And this recovery of about 70-or-so Bcf is the plan of this first phase of 2 wells, and it’s just a question now of where to site these wells. We’re working very well with the BP team who continue to drive the project forward, and we’ve had people in their offices and working very closely with them to bring this to a sanction in the second half of this year.

Sea Lion, which you will be very familiar with, continues, of course. We — it remains a material opportunity for the group. Discussions with the senior debt providers continues. We signed the heads of terms with Navitas. And we’ve known the Navitas team for quite a while, although they’re a new company to some of you in the room. They represent a significant step forward, of course, because they’re sharing in the pre-first oil funding. They bring additional sources of debt funding to the project as well. We significantly derisked the Phase 1 of the project. As you will remember, it’s a conventional FPSO project, very similar to the Catcher development. We’ve added a third drill center, plateau rates over 85,000. So we’ve got a very collaborative relationship with our Tier 1 supply chain. The critical path to sanction remains securing senior debt support for the project.

In terms of the carbon footprint, there’s a lot of work going on. Actually, we’ve reduced, over the life time of the project, we’ve reduced the carbon footprint by about 10% on the project itself so far in terms of the offshore kit. And we believe, in terms of offsetting, we can make at least another 10% on the islands. We’re working with the Falkland Islanders on the projects such as replanting of the tussock grasses, pit remediations, some planting of noninvasive species, electrification of the onshore operation and so on and so forth. So again, work going on to make that a carbon-neutral project. And to the extent that it can’t be in the islands, we would plan to invest in nature-based projects in the U.K., which after all is where the supply chain is delivering materials to the islands for this project.

Tuna. We’ve talked before about Tuna. We found around about 100 million barrels. We’re planning to export the gas to Vietnam to be used in power generation, of course, ultimately displacing coal and other poorer fuels. We’ve agreed the heads of terms with the Zarubezhneft who some of you will be familiar with. They’ve planned to carry us for a 2-well appraisal program. And all being well, we would then move straight through to a very swift development. Again, designing this project to be a low-carbon project. That concludes my brief review of these discovered resources.

I’ll now pass over to Tim Davies, who will talk through some of our exploration organic growth projects.

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Timothy Davies, Premier Oil plc – Group Exploration Manager [5]

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Thank you, Robin. Always a tough act to follow. Now for the glamorous bit. It’s not often I have to say that I hear exploration referred to as glamorous in any way, shape or form. What I’d like to do on this first slide is just take you through the 2019 exploration and appraisal highlights and then have a quick look at 2020 and potentially into the early 2021.

2019 was a very successful year for exploration. We had great success with the Zama appraisal campaign in Mexico. It’s not often we increase resource base when we do appraisals on fields, but the extensive 3-well campaign on the Zama field tied the continuity of the reservoir in the north-south sense. We tested the fact that the oil water contact conforms to the seismic flat spot that we could see on the data. And we conducted extensive testing at the reservoir. So we’ve shared we had good reservoir deliverability. This led to an overall resource upgrade from about 740 million barrels gross to 811 million barrels gross on the field. The unitization process continues at pace, following the conditions and terms laid out in both the pre-unitization agreement and the PSC. So that will continue as we go through 2020. The sales process is ongoing, and we’re continuing discussion with interested parties.

We had the Tolmount East discovery in the U.K. We also discovered which has been spoken about by Robin and Stuart. We also had extensive 3D acquisition over Block 30 in Mexico. Some more of that later. Also, part of 2019 success was the capture of new acreage. This was the form of our entry into Alaska North Slope, which I’ll talk about in a minute. And also the Catcher and deepening of position in the South Andaman Sea with addition of the Andaman I and Andaman South licenses. Again, I have a couple of slides on that.

Looking forward, 2020, we’ve currently got the Alaska well, Charlie-1 drilling. That’s spudded on the 2nd of March and a bit spinning as we speak. I can say we’ve learned an awful lot about ice and how to conduct business on the North Slope there. A few slides on that in a minute. By the end of the year, by Q3, we’ll have spudded the Berimbau/Maraca well in Brazil. I have a slide that talks to that.

If we just look at the map in the top corner here, you can see, over the next 18 months, we’ve got a 6-well exploration campaign that is targeting over 300 million barrels of net risked resource. And that’s got some really exciting prospects with Alaska, Brazil, 2 wells in Mexico, Block 30, and also 2 wells in the Andaman area, Andaman Sea of Indonesia.

Into the Alaska North Slope, a bit of a step for Premier into Alaska, managed the new country entry. Basically, it’s a renewed industry interest in an under-explored conventional reservoir up on the North Slope. All the previous historical exploration was targeted at the Jurassic until the recent discoveries that you can see made by Armstrong at Pikka and Conoco at Willow. This opened up a Cretaceous play in the Brookian reservoirs. And essentially, what you’ve got is you’ve got a beach sitting up here, the pro grades across the basin from west to east. And off the top of the beach, down into the basin core, you’ve got Tam and Meltwater and our own prospectivity at Icewine, which are the basin-floor fans that have since shed out into the basin.

We’re drilling, as I said, on the Icewine well. The Charlie-1 well is actually twinning the BP Malguk well that was drilled in 1991. That intersected 251 feet of conventional light oil pay in the Cretaceous, but the primary target for that well was the Jurassic. So they left the Cretaceous, and they were focused on delivering the Jurassic. We’re twinning the well. We’re about 500 meters away, and we’ll carry out a flow test on the well to try and improve deliverability from the Torok sandstones in the area, which will allow us to move forward to development.

Slightly novel approach. We actually drive the rigs out there on ice roads or a tender wilderness road as they’re called. I think it topped out at about 1.5 miles an hour, a 48-hour drive to get us from Deadhorse out to the well site location. Here, you can see, is the ice pad with the rig in location over the drilling basin hold.

What have we got on the slope? We farmed in for 60% interest on the license. We’ve spudded the well. The flow test will only be about 200 million barrels — 200 barrels of oil a day because that’s a vertical well and vertical test. And this type of rock, what we need to is move forward to the horizontal wells, which are being drilled up at Pikka and Willow and are seeing over 3,000 barrels a day production. Our test in the vertical section of the Charlie-1 well will prove that we can deliver the oil from the rocks, and that will allow us to upscale to a commercial development flow rate.

You will have seen from our partners, Energy 88 (sic) [88 Energy], they talked through a series of stacked phase up through the section. There are actually 7 potential in-tools of stacked sands, but our focus and the numbers that we’re looking at are primarily focused on the Torok reservoir sections in the upper stellar, middle stellar and lower stellar. Why are we so focused on these? We’ve got an extensive 3D data set. And using VpVs analysis on the seismic, we can actually see the sands, which gives us a very good idea of where they sit. The stacked play and the shallower sections up to Schrader Bluff, the well will go through those, and hopefully, we’ll see oil, but they’re not optimally located for those prospects.

Moving on to Brazil. We hope to spud the well in Q3. It provides us with a stacked target. We’ve got the Berimbau channel sitting up in the shallower part of the section, creates the channel cutting back on to the margin, above a nice tilted structural 4-way dip closure at Maraca. The Berimbau channel is a high-risk prospect because of its stratigraphic nature of the trapping geometry, and we see Maraca as a lower-risk prospect. We have potentially a 100 million to 600 million barrels of potential resource to be accessed by that well, which we hope to spud in Q3 this year.

Gross well cost has been very good, actually, $45 million. That’s great negotiation, access to the right rigs, and the Brazil team has done a very good job in securing that. That well on the license will fill — fulfill the complete license obligations. We originally had a 2-well commitment for the license. But with negotiation with the Brazilian government, they’ve said that by deepening the section and testing this deeper play, we’ll have fulfilled all our license commitments. So fingers crossed for that one.

Moving on to Mexico. I touched on the fact that we’ve just got a new 3D across the entirety of Block 30. What you can see on the seismic line here is we do — and on the new data that we’ve just got in, which is the PSTM data, we can still see the flat spot. We see good conformance to structure of the seismic against — in the footwall of a bounding fault. Exactly the same trapping geometry that we saw at Zama, not quite the same scale, but with the same seismic signature and shutoff and closure, which is a good place to be. What we’ll do on the rest of the seismic, the block wasn’t covered in its entirety by 3D when we bid for it. We now have the entire block covered by 3D, which will allow us to further delineate the other prospectivity on the license for a second well in Mexico as we go forward.

Moving on to the Burgos acreage. This was a cheeky little bid, picking up some acreage off the sort of proven Sureste Basin. Very good terms and conditions, we secured this for 24% government take, whereas everything in the Sureste Basin is going for 75% plus. We’ve got 3 potential Oligo-Miocene prospects with resource ranges of between 30 million to 150 million barrels. This is highly prospective because we’re in less than 65 meters of water. You’ve got the whole Willcox Basin sitting onshore to the north of here with export and access and route. And we’re just close to the American border, so we can bring facilities and kit from the U.S. should we require it.

On the initial sort of fast-track volume of the reprocessed data we’ve got across Burgos, the team has also been able to work out this deeper, holistic Jurassic shale play. It’s still a sort of concept at the moment. We continue to work it, but we do see, in Mexico, the Arenque field here that produced from a very similar holistic shale reservoir in the Jurassic section. And that section in the Jurassic could be a sizable reservoir, but we need to continue to work that up and develop it potentially in excess of 250 million barrels.

Just moving swiftly on to the Andaman. I’m known in the company as a bit of a geophysical skeptic, I have to say, but we seem to be having quite a bit of success with flat spots, rock physics and doing the work. The team led us into Andaman. We picked up Andaman II, built on that position with Andaman I and Andaman South. And from the initial sort of 3D survey that we’ve completed across the Andaman II block, we’re beginning to pull out structures like the Timpan structure you can see on this slide.

Again, we’ve got a very well-defined structural closure and flat spot. And one of the key things for me when we’re looking at the seismic is actually do the amplitudes, shut off with the dip closure all the structural contours. But as you can see on this map, there’s very good conformance of the amplitudes to the actual structural closure and the dip of that structure, which gives us very high confidence in actually finding hydrocarbons or predominantly gas in this area.

What we have in Andaman as well is brownfield LNG terminals, the Arun Terminal up on North Sumatra, which gives us a great exit route for any hydrocarbons we find on these licenses. Timpan, we’ll target about 1.5 Tcf of gross unrisked resource. It is a large 4-way dip closed structure, as you can see, with a very good, strong AVO response. There are considerable volumes, additional volumes on all of that acreage in the Andaman Sea. We see that as highly prospective, and we look forward to drilling the 2 wells out there in 2021.

So that’s it for me. I’ll hand you over to Tony to close out. Thank you.

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [6]

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Thanks, Tim. So briefly by way of summary. Guidance for 2020, currently at 70,000 to 75,000. We’re slightly ahead of plan as we speak, and we will add to that with the proposed acquisitions. Run rate taking us at or around 100,000 barrels a day, and we’ll update our guidance in due course. At the budgeted rate of $60, we generate free cash flow from our existing assets. That will be supplemented by cash flow from the acquired assets. And that, of course, is before any disposal proceeds added in from the Zama sale.

You’ve heard about a quite significant program of infill and workover activity, which will add up to 15,000 barrels a day on the short-term incremental basis, more than offsetting natural decline and Tolmount, of course, at the end of this year. And Tim has just described both the short-term drilling program, 300 million barrels of net risked resource from the wells already planned over the next 18 months with a whole series of wells beginning to fill up the pipeline beyond that, in Andaman, in Mexico, appraisal in Tuna, et cetera.

As you heard from Robin, we’ve got an extensive program across all our assets to reduce emissions. That will be supplemented by our commitment on new projects to be net zero for those projects that will substantially reduce our emissions over time, in line with our new stated targets. We’ll report on both our emissions and any related carbon-offsetting measures as we go forward.

Production profile, terms, the producing asset base, including Tolmount, the blue area represents current unsanctioned projects such as Tolmount East, which will kick in, in due course; the gray, the proposed acquisitions. You can see how they contribute significantly over time so that we have short-term rising production to 2022 and out to 2025, we continue to produce above today’s levels. New projects, Tuna, Sea Lion, potentially Alaska will kick in after 2023.

Given that we are about to issue a prospectus, I can’t translate that into financial forecast, but we can talk about capital allocation. Those of you with a good memory will remember a very similar slide to this 2 years ago. I’m pleased to say that the shape of this slide, given that it is a long-term plan, has not changed substantially. It was always the case that in the early years of the plan, the emphasis would be on debt reduction. And that has proved the case — to be the case in 2018 and ’19 at the expense of new projects. Over time, that will reverse as debt reduction will be in line with our reserve reductions under an RBL facility, and more of our capital will be available for new projects or, indeed, if choose not to go ahead with those new projects, shareholder returns.

The outputs of this model continue to be very consistent at $65 a barrel. We will have positive free cash flow production, underwritten by the new acquisition assets, will be more than 100,000 barrels a day. And our covenant level goes below 1x, which will put us in very good shape for our forthcoming refinancing. In short, positive free cash flow with net zero emissions, which is our strategy and, frankly, I think, should be our strategy.

Questions.

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Questions and Answers

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

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Werner?

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Werner Riding, Peel Hunt LLP, Research Division – Oil and Gas Analyst [2]

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One each for Tony and yes, I forgot your name, Richard and Robin. You achieved unit OpEx of $11.4 per BOE this year or last year. Earlier on, you mentioned potential for $15 per BOE, obviously, excluding lease costs for this year. With Tolmount, Andrew and Shearwater being introduced, where do you see that going in 2021?

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

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I think the answer to that is $15 a barrel is pretty consistent going forward over the longer period. I don’t know whether you want to…

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Richard Rose, Premier Oil plc – Finance Director & Executive Director [4]

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Yes. I mean, just to be clear, I mean the reason it’s gone up slightly this year is, on a per-barrel basis, is not because we’re seeing absolute cost going up. It’s a mixture of the fact that production is coming down with a flat cost base. The other thing is we do have a lot of costs in sterling. We set the budget at [135]. It’s not 135 at the moment. So I’m not trying to give guidance that we’re going to beat the budget. But if we see current FX rates, we will expect that to be slightly lower.

But I think Tony is absolutely right. The average cost of the BP assets is in that kind of $15 to $20 range. We think we need to be a bit careful because until we get our piece on the table, we can’t guarantee it, but we would expect to deliver some cost savings on the BP operating cost profile, and Tolmount will initially have tariff costs, et cetera. So I think if you’re in that kind of $15 to $20 range before we start giving formal guidance, I think you’re not going to be too far away.

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Werner Riding, Peel Hunt LLP, Research Division – Oil and Gas Analyst [5]

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Okay. And Robin, on Sea Lion, you mentioned that you need to get the senior debt piece in place before you take a project sanction decision. So could you just please paint the picture exactly what needs to happen from here and what’s your timing expectations?

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [6]

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Yes, of course. I mean I’ll take that. We submitted the payments at scope, project information memorandum in the fourth quarter of last year to U.K. Export Finance. At that point, of course, we did not have the acquired — assets to be acquired in the profile nor the related equity offering. Both of those are material events for Premier, $500 million of new equity, up to $1 billion of cash flow in the relatively near term from the assets clearly changes our credit position. So UKEF asked us to resubmit the documentation pro forma of the acquisition. We’ll do that as we go through the approval process and continue those discussions.

Mark.

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Mark Wilson, Jefferies LLC, Research Division – Oil and Gas Equity Analyst [7]

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Mark Wilson, Jefferies. We can work out what your CO2 emissions are. You’ve given us the emissions per barrel. So within that 7-year balanced capital allocation, could you tell us what is the annual cost or the absolute cost of these nature-based offsets?

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [8]

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Yes. I’d emphasize again the fact that we’re trying to engineer out our emissions before we get that far. I think openly, pricing carbon offsetting is one of the difficulties that the whole industry is grappling with at the moment. At one end of the spectrum, we’ve got, frankly, very cheap dollar per ton tree planting schemes. At the other end of the spectrum, I suppose you’ve got ETS credits. Currently, we’re operating under the EU scheme. That will be replaced by a new U.K. ETS scheme, which, at today’s pricing, is of the order of $25 a ton. I think the answer on average will be somewhere in the middle. That gives you probably a range of $10 to $15 per ton of emission.

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Mark Wilson, Jefferies LLC, Research Division – Oil and Gas Equity Analyst [9]

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And Richard, could I ask regarding the court scheme next month? A lot of focus out there regarding current commodity prices, gas prices. Could you remind us what the court actually rules on and whether those variables go into that decision?

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Richard Rose, Premier Oil plc – Finance Director & Executive Director [10]

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Yes. I happen to be a bit of an expert in law at the moment, and it’s this month, by the way, so it’s 17th and 21st. I mean our understanding or my understanding and, as I say, I’m not a lawyer, so appreciate this, is that the scheme hearing is to focus on whether the scheme is fair. With the creditors’ vote and the information on the expense statement that’s gone onto creditors’ and what they’ve voted on is, is their chance to vote on the commercial — on the merits — commercial merits of what we’re trying to do. The scheme itself, it is up to the court to decide whether what we presented is a fair scheme, a scheme for creditors. And that is the, what we believe, is the narrow definition that the court will opine on, including class structure and various things. We believe we have presented a very fair scheme to creditors, and we’ll be presenting that at the court in the sanction hearing.

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [11]

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Al.

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Al Stanton, RBC Capital Markets, Research Division – MD & Oil & Gas Equity Analyst [12]

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Al Stanton, from RBC. I have 2 completely unrelated questions. First, for Tim, and then going back to the emissions. On the drilling in Alaska, you have 2 wells. You’ve got the existing well and then you have the well you’re drilling at the moment. Does that give you the insight to put a horizontal well in between them? Can you move quickly onto that?

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Timothy Davies, Premier Oil plc – Group Exploration Manager [13]

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Yes, very much so. So the plan, as we currently guided, if we get the flow rate that we hope to achieve from the current well, we’ll suspend the well. We’ll come back and drill a horizontal, which will be a commercial proof of concept. So what they’re doing is they’re getting 3,000 barrels a day from horizontal wells out of the Conoco and Armstrong production. So that’s what we would do.

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Al Stanton, RBC Capital Markets, Research Division – MD & Oil & Gas Equity Analyst [14]

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Okay. And then with respect to the emissions, when you’re talking to lenders, how much do they care at the moment? And you mentioned the U.K. Export Finance. Are they listening to what you say on your covenant?

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [15]

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Yes. I think different banks put different emphasis on it. If we were to have a conversation, as we did last week with our friends from Norway, you can imagine that there’s a very heavy focus on what our climate change policy, our emissions record is. Other banks may not be quite so focused on that. I think UKEF takes its direction in terms of its investment policy from government policy. The government has — this government has been pretty clear that it does not have an anti-fossil fuel policy. It has an anti-coal policy in terms of the policy guidelines it gives to UKEF.

[Chris]?

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Unidentified Analyst, [16]

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Let me start by saying thank you to Robin for everything he’s done for Premier Oil for the last few years. Keeping a stable level of production performance, is really helped by Richard to sort the balance sheet down. So thank you very much, Robin.

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Robin A. Allan, Premier Oil plc – Director of North Sea & Exploration and Executive Director [17]

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Thanks, Chris.

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

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Well done, Robin.

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Unidentified Analyst, [19]

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Gracias, Robin. And best of luck to Stuart because namesake — they say a few namesakes are mine. Sorry, they say a few namesakes are mine. I hope Stuart succeeds. Two questions, please. Firstly, on the Catcher area, you’ve got the debottlenecking and 2 infill wells coming. Yet, you still seem to be implying there’s decline in Catcher next year versus this year. That seems to be quite aggressive, considering you’ve got those 3 positives coming up. Secondly, what does that mean for the costs as well? Can you get the FPSO operator to get the cost down now or when you renegotiate the FPSO contract in 2024?

And then secondly, questions about Indonesia. It looks like the key pricing crossover point was around $4 an MCF for LNG versus piped gas. How does that flow through then into pricing for ’20 for you, for your gas for 2020 and ’21? What unhedged prices are you seeing? And is that likely to come down if we see further low LNG prices sustained into 2021 onwards?

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

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I’ll take Indonesia, and Stuart can take Catcher. I think a balance between LNG and pipeline gas price competitiveness was reached towards the end of last year when they both sort of flattened out at around $7 or $8 per MCF, so a bit higher than you suggested for the Asian market, obviously. And then we started seeing more of a balanced demand picture from Singapore.

Our own pipeline gas pricing is determined by the development of HSFO pricing. And what we’ve seen over the last 12, 18 months is quite a significant drop in HSFO pricing in relation to IMO legislation. We protected ourselves in advance by a very significant hedging program. Unusually for us, I think something like 70% of our after-tax production was protected by hedging because, frankly, we saw that HSFO drop in price coming.

I think we’ve seen recently a pickup in HSFO pricing. I think, generally speaking, the experts in the area expect HSFO pricing to recover as the shipping industry, the refining industry is taking actions, for example, on putting in new scrubbers. So I would expect from this point really that HSFO pricing would recover. That would tend to suggest our own pipeline gas pricing will recover. That will then be sort of naturally offset. If LNG spot pricing doesn’t recover, Singapore will take more — clearly take more of the cheaper gas, subject only to the 90% take-or-pay contract that we have.

If you want?

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Richard Rose, Premier Oil plc – Finance Director & Executive Director [21]

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Yes. I mean I was just going to say, I mean, we’re treating the current production level as very high. It’s a bit of a windfall. Our forecast for the full year are only marginally above take-or-pay. So we would expect, as Tony says, if the pricing differential goes against us and LNG remains in surplus, then we’d see production slip back down. But as I say, we are protected with take-or-pay. So we saw that for last year. I mean our take-or-pay level is around 11,500, 12,000 barrels a day for the full year. We’ve currently been doing 15,000, 16,000 barrels a day, great, nice windfall. We’re winning on production. We’re winning on the hedge. But in terms of forecast and planning, we assume that those rates won’t continue for the full year.

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [22]

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Stuart, do you want to talk about Catcher?

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Stuart Wheaton, Premier Oil plc – Chief Technical Officer [23]

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Yes. A little bit about Catcher going forward, so yes, maintaining plateau production until the end of this year. That would have mean we’ve been on plateau for 3 years. The original sanction or thereabouts. The original sanction case was that we would stay on plateau only for about 20, 22 months. So the decline points got to come at some point. What we’re doing in our future forecast is basically retaining the same sort of shape of the decline, but with the higher reserves base that we indicated earlier. So that decline really hits in 2021.

I think it’s worth keeping in mind that the 3 Catcher fields connected to the FPSO are all still relatively thin sands. They’re only 20, 30 meters thick. So once the oil sank, the water inevitably has to come in quite quickly. So even though the water cut level has been retarded to this point, when it arrives, it will be a steep rise. That’s what we’re projecting.

But of course, things like doing the 4D seismic will give us a better indication about really how has the water, and there’s some gas caps as well there, how that’s moving around and recalibrate the model potentially going forward. But likewise, drilling these infill wells, we think we’ve drilled most of the original sweet spots on Catcher and remembering that these horizontal wells are, in some cases, 2,000- or 3,000-foot long. It kind of leaves less space for new things. So the smaller infill — the infill wells coming are somewhat smaller. They typically have 1.5 million, 2 million barrel type recoverable with each well. So it’s a law of diminishing returns at the moment. So even though we can add them, we can’t add them fast enough to project against the decline. So that’s why we have that sort of shape question.

On the costs, the actual Catcher FPSO contract does have a shape on it that comes down after 3 or 4 years. So that’s built into the OpEx or at least for the lease side of things, which is the substantial part. The other OpEx on the field, we actually project as being reasonably flat for 6 or 7 years and mainly because we’re dealing with a lot more water. So you have extra production chemicals and other things and other issues to deal with. So even though we clearly will work OpEx and try to minimize, there’s some offsetting effect as well. So inevitably, your unit OpEx has to be shaped somewhat like your production profile.

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [24]

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And I think you’re right, Chris, there will be a time, and it’s probably even now or not too far away, when we’ll be sitting down again with BW and resculpting the profile based on updated production forecast but also on a lease extension.

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Stuart Wheaton, Premier Oil plc – Chief Technical Officer [25]

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Yes. We can certainly see sort of year 8, 9 and 10 are right there to be had.

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [26]

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Mr. Hubbard?

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James Richard Hubbard, Numis Securities Limited, Research Division – Analyst [27]

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James Hubbard from Numis. Two questions. Brazil, the commitment well. When people use the phrase commitment well, it’s kind of like we’re not really sure it will be that successful. We’ve got to drill it, so we’ll do it anyway. So I’m just wondering, did the auditor put a chance of success on that? And maybe I should know this, but yes, is there a chance of success that someone has put out there in an audited reserve report? And how would you rank it in terms of the exciting prospects you’ve got coming after that?

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [28]

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I’ll answer that straight away and that, Tim, you intend the chance to answer it in a technical way. But I would say, higher on volume, higher on risk than the rest of our exploration drilling in the near future, probably 1 in 4, 1 in 5. Tim, do you think that’s fair?

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Timothy Davies, Premier Oil plc – Group Exploration Manager [29]

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Yes, that’s where I was going, high volume, high risk. That’s the…

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James Richard Hubbard, Numis Securities Limited, Research Division – Analyst [30]

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Okay. And then on emissions. So you have a hopper, lots of ideas. And I’m just wondering, do you — is that like a financial returns analysis, it’s going to be done on choosing? Because obviously, you could just say forget costs, we’ve got to achieve it no matter what. And if there is, are you using this ETS carbon credit kind of forward curve to do that? Or is it more a case of, no, there’s deeper philosophical reasons beyond financial returns here, and we’re going to do it, to hell with the returns?

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [31]

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I mean I’ll give my answer. I’ll let Robin speak as well. Obviously, we’re not going to spend money that we don’t need to spend. But equally, I think it’s very important if you make a commitment that — not just you live up to that commitment, but what you do through that commitment is effective. I think going forward, there will be opportunities to participate in so-called carbon-offsetting schemes, which ultimately turn out to be not very carbon offsetting. So we’re going to put the appropriate corporate governance. It’s one of Robin’s future roles around any investments we make on a carbon-offsetting basis, yes, to look at the economics of those investments, but also to make sure that they are bonafide carbon offsetting.

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Robin A. Allan, Premier Oil plc – Director of North Sea & Exploration and Executive Director [32]

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And just returning to the hopper. So yes, we look at the cost of everything. But of course, I chose the example from Indonesia very specifically because it’s a good example of where you actually are reducing your emissions and you’re saving money. So they’re not all cost negative. The teams around the world are charged with filling that hopper regardless of costs. So what is physically possible to do regardless of cost, and then we’ll analyze everything and try and figure out whether it’s feasible to undertake that work. And some of them, yes, you’re cutting out flights, for example, unnecessary flights, reducing ship movements, stuff like that, saves you emissions, saves you money as well. So they’re not all loss-making, if you put it that way.

In terms of the forestry offsetting, it’s more of a discussion internally about the quality of the offset rather than the price. There’s no point doing some cheap offset. It’s worthless to the world and the community because our own staff won’t recognize it. Investors won’t recognize it as being worthwhile. We need to do — the reason we’re focused on forestry-based offsets is because of the geographies we’re in. So in the U.K., Indonesia, Vietnam especially, these are places where forestry schemes can have a direct relation to our teams in the country.

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [33]

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David.

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David Matthew Round, BMO Capital Markets Equity Research – Oil and Gas Research Analyst [34]

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David Round from BMO. You’ve been pushing out a lot of your decoms. I’m just trying to clarify here, is Huntington your first major operated decom project? And if it is, how important a yardstick is that for future decom, which obviously is a big consideration for you guys? And could you just let us know or give us an indication in terms of what you’ve provided for in terms of that project?

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [35]

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Yes. I think it is probably fair to describe it as the first major one. I mean, actually, technically, it’s the second decom project we’ve run on Voyager because if you can remember, the Voyager came from another field, which we’re also the operator of. But you’re right, I think it probably is a good test of abandonment costs, although I think we need to put it in context. It’s a floating production vessel. We clean up the brake lines, we cut the moorings and we float the boat away, that perhaps a truer test of abandonment costs overall will be the cost of abandoning the wells, which will be spread over something like a 5-year period. And that — when we look at that portfolio, it’s probably the cost of well abandonment that will drive abandonment costs going forward.

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Richard Rose, Premier Oil plc – Finance Director & Executive Director [36]

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Yes. So just on — I mean just on the number, I think we’ve got $120 million, looking at somebody here, around the $120 million provided on. And there’s a couple of phases there. There’s the — when you say the FPSO way, you clean and flush the lines, then we need to come back, take the flow line subsea, get away and then we need to do the wells. So I haven’t got the exact split between them. It’s almost 1/3, 1/3, 1/3, I think, and they will be done in phases. So the last thing to be done will be — I think it’s 5 wells on Huntington. And we’ll batch abandon those with the rest of the programs we’ve got, so they will be quite late in the line.

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Timothy Davies, Premier Oil plc – Group Exploration Manager [37]

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Yes. The significant sort of advantage of removal of Huntington, it’s actually quite modern. So it’s been there less than 10 years. So all of the wells are pretty clean and new. So it should be relatively sort of efficient and smooth operation. It’s those older facilities, the older wells, which — where operators have our biggest challenge. So — but we’ll start with the FPSO removal and then subsea in the next couple of years and then the wells after that.

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Richard Rose, Premier Oil plc – Finance Director & Executive Director [38]

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I mean there’s 2 other things I’d say on U.K. abandonment. One, obviously, tax. We have tax history. So as we start incurring those 18, 24 months later, once we felt the returns, we’ll get that back. And from an overall debt position, we forget, we’ve got $400 million of U.K. LCs. So even though we’re deferring, but we actually start spending that. We are almost like we’ve prefunded that from a kind of gross debt perspective. So some of those LCs will start coming back as well.

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [39]

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[Stefan].

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Unidentified Analyst, [40]

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So [Stefan Fuko from Optus]. I had a question on Zama. With the oil price having dropped quite a bit over the last few weeks, did that have any impact on discussions with counterparty pricing expectations already or not yet?

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [41]

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No. As you know, we received bids on Zama in December. We’re pretty comfortable with the outcome of those bids. But turning those into final agreement has become intertwined, I would say, with the unitization process, as we’ve said and as has been discussed publicly. I think that should not really be a surprise. The potential purchasers are wanting to know what they’re buying exactly, which I think is common sense. So the process itself really needs some form of resolution or at least a comfort level on both sides as to what the outcome of the unitization is. But no evidence that the pricing that we’ve discussed with those potential purchasers is being impacted by the current oil price volatility.

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Unidentified Analyst, [42]

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And the bids are binding, pending unitization? I guess there is a timing…

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Anthony R. C. Durrant, Premier Oil plc – CEO & Executive Director [43]

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No, they’re not as simple as that, but utilization is a key factor in reaching a final agreement.

Thank you very much. We’re available, of course, for any one-to-one questions going forward. Thank you again for your attendance.

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Richard Rose, Premier Oil plc – Finance Director & Executive Director [44]

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Thank you.

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