Cairn Energy Plc (OTCPK:CRNCY) Full Year 2018 Earnings Conference Call March 12, 2019 4:00 AM ET
Simon Thomson – Chief Executive Officer
James Smith – Chief Financial Officer
Paul Mayland – Chief Operating Officer
Eric Hathon – Exploration Director
Conference Call Participants
Werner – Peel Hunt
Sasikanth – Morgan Stanley
Michael Alsford – Citi
Al Stanton – RBC
Chris Wheaton – Stifel
James Hosie – Barclays
Alwyn Thomas – Exane
James Thompson – JPMorgan
Okay, morning, everybody. Welcome to Cairn’s results presentation. I’m Simon Thomson, Chief Executive. With me are James Smith, CFO; Paul Mayland, COO; and Eric Hathon, Exploration Director. So as in usual way, we’ve got a presentation that we’ll walk you through this morning, and we’ll be very happy to take questions at the end. It’s being webcast, so there’ll be microphones available. So if you do have a question, please, for the sake of those listening, state your name before asking the question. I’m sure everybody has been in this room before, but just in case, in the event that the fire alarm goes off, you can see the clearly mined – signed exit there. And the master point is outside, in the square.
Okay, before I turn to the first slide, I just want to say a few words on India. I mean, obviously, you will have seen our announcement yesterday concerning the timing of the arbitration award. There’s probably not a great deal more that I can add today, but there’s couple of things that I do want to emphasize. The first thing, obviously, we clearly understand that this is frustrating for shareholders. The timing is out with our control and the timing has changed, but secondly and importantly, that’s the only thing that’s changed, so we remain just as confident in terms of the outcome of this arbitration as we have been right the way through. So there is a revised timing in respect of the outcome, but it remains a significant value driver for us, and nothing has changed in that respect.
Now I want to just move on to the value that we see in the underlying business, if you turn to that first slide. I mean a couple of words on the company, where it sits in terms of its strategic delivery today. As you know, our mantra is to create, to add and to realize value. And we believe that a differentiator has been our willingness to look at returns to shareholders, whether through buybacks, special dividends or whatever, in delivering that mantra.
Obviously, five years ago or so after the last cash return, we set about rebuilding the company to offer a balanced business. We wanted to have something that gave shareholders significant upside potential in terms of our drilling program backed by balance sheet strength. And we believe that, that is what we have today.
So if you look at this slide and starting from the top left here, our production from our North Sea assets. Obviously, underperformance at Kraken countered by outperformance at Catcher provides all of the cash flows we’ll require to meet our commitments. And those cash flows are generated, looking at the second bubble, in a company that has significant balance sheet strength and financial flexibility. So that allows us to redeploy those cash flows into our exploration activity whilst at the same time retaining the flexibility to be able to follow up on our developments and consider any accretive, new venture activity.
When you look at the sustainable investment in the exploration program, we’re really excited about what we see in front of us this year. So the program, which Eric will talk about in more detail, is seeking to access around about 1 billion barrels of gross resources. And at the same time, we continue to look at bringing in, reranking our new venture portfolio. So the company continues to focus on what is the best prospect to drill. That changes through time, obviously. And we’re looking at 2020, 2021, 2022.
All of those have to satisfy our strict investment criteria to be bought into the company. You then look at the follow-on from exploration success, and obviously we’ve got two homegrown developments in Nova in Norway and SNE in Senegal. Both of those give us the ability not only to sustain but also to enhance cash flow generation out into the medium to longer term. And when you tie all of that back together, I’m coming back to the point I made at the beginning, we believe, where we sit today, we do offer significant upside potential whether through the drill bit or through portfolio management. And we have been active portfolio managers in the past. We continue to desire to be so in the future.
Okay, if you look at the next slide. As you can see, it’s going to be a busy year for us. So there are a large number of wells. So seven wells can be drilling in this program in 2019, five of them operated by Cairn. So that’s where we want to be in terms of the balance of Cairn-operated activity. As I say, Eric will talk about that in more detail, but you can see also there is a lot of other activity in terms of contingent well planning for future years, ongoing seismic and data acquisition.
Then you look at the bottom of that slide and we look at our development activity. Again, Paul will touch on all of that, but the key messages are they’re both progressing on track and they’re both making excellent progress. So Nova fabrication is ongoing now in terms of the facilities required to be added to the platform and the tieback, and it remains on schedule for first oil in 2021.
In Senegal, you’ll have seen the announcements, various announcements from Woodside, now the operator, following a successful transition from us. The ESIA was submitted, has now been approved. The exploitation plan was submitted, now has technical approval, leading towards FID in the midyear, which as I say Woodside have reconfirmed remains on target. And also, as you’ll have seen from their announcements, there’s multiple FEED work ongoing. And again, Paul will touch on that.
So look. It’s a busy, it’s an exciting year for us. There’s a lot that we believe we’ll be able to come back to you with in terms of potential upside in the portfolio. We’re working hard on that. So we’re looking forward to coming back to you, coming back to you on exploration drilling results, coming back to you on progression of the developments and coming back to you on the Indian resolution.
And with that, I’ll hand over to James.
Thanks, Simon. And morning, everyone. So in the next few slides I’ll take you through key results for 2018 and then a look forward to the year ahead. And first of all, an overview of the current funding position. So cash flows during 2018 took us to a year-end cash position of $66 million. In terms of working capital, at the balance sheet date, we had an oil sales receivable of $39 million relating to 2018 production and remaining outgoings of $30 million relating to 2018 CapEx, so a small net positive cash, working capital position.
The $575 million North Sea reserve-based lending facility was drawn $85 million at year-end. And during last year, we extended the maturities of that facility out to 2025 in order to incorporate the Nova field development into that facility, and following that, all or close to the full facility amount is now available to draw.
In Norway, we continued to use an exploration financing facility which effectively prepays the tax rebate on exploration activity accumulated during the year. So drawings under that are usually roughly equal to the rebate that’s been accumulated during the period.
Looking forward to the future capital program. Work on our project financing facility for SNE is now well progressed. We’ve been working both with the Senegal government and our joint venture partners on structuring, as well as with a core group of expected lenders regarding capacity and terms. And work on both of those streams is now well progressed in readiness for a formal launch so that we can close in conjunction with FID in midyear. And finally, to reiterate Simon’s point, whilst we remain confident of our – of the validity of our $1.4 billion arbitration claim against India, the timing does remain uncertain, and then we therefore maintain a business plan that is fully funded without those proceeds taken into account.
Looking at some of the key figures for 2018. As we’d already guided at the beginning of the year, already announced at the beginning of the year, production of 17,500 barrels a day gave revenues of $396 million on an average realized crude price of $68 a barrel. Average Brent prices during the period were approximately $71 a barrel, so that obviously indicates strong price realizations both for Catcher and Kraken crudes, helped in part with global outages of heavier crudes across the slate. So with average production costs of $20.50 a barrel, that gave operating cash flow from production of $229 million, excluding that $39 million receivable that I mentioned earlier.
In terms of the income statement, we posted an impairment on our Kraken field carrying value based on currently constrained production levels, which led to an operating loss of $182 million. And as we’d already partly recognized in the midyear 2018 results, during the year, the Indian income tax department sold the shares in Vedanta Limited that they had seized from us, which led to a derecognition of the value of those shares and a P&L loss after tax of $1.1 million.
Moving on to the guidance for this year. We anticipate production in the range of 19,000 to 22,000 barrels a day, as we’d already guided in January, before the FlowStream take; and an average production cost of around about $20 a barrel. So at the middle of that range and at prevailing oil prices, that would give operating cash flow for this year from oil production of around about $300 million. And as you can see, we’ve hedged just about 1/3 or just over 1/3 of those expected volumes with floor prices in the mid-to high-60s Brent.
Looking now at a reconciliation of cash flows during the year. The opening cash position in the beginning of 2018 was $87 million, operating cash flows from oil production during the year $229 million. We drew, as I said, $85 million on the RBL facility and $37 million on the exploration finance facility in Norway, to take us to the top of the chart there.
CapEx on the two producing fields of $105 million was $35 million on Kraken drilling, which is ongoing; and $70 million on Catcher for the completion of the FPSO at the beginning of the year and development drilling during 2018 which is now concluded on the field. CapEx on the SNE and Nova fields last year was $59 million, bringing Nova into the development phase and SNE into FEED phase.
And then – and exploration cash outflows of $121 million represented a net-of-tax program of $88 million, being principally the four wells in the UK and Norway region, Tethys, Raudasen, Ekland and the Agar-Plantain discovery; as well as planning for this year’s Mexico campaign. Then at the end of the chart there, new ventures costs; admin expense, which includes the refinancing of the RBL facility and purchase of our own shares, gave a year-end cash position of $66 million.
Looking now to CapEx guidance for the year. $25 million of development expenditure in the producing assets relates mainly to the completion of the DC4 drilling on Kraken in the early part of this year. On Nova, $65 million relates to the start of work on the modifications and the new module required at the Gjoa host platform. And in Senegal that $40 million relates to pre-FID costs only, so effectively the pre-FEED and FEED activity that’s currently ongoing.
On the exploration front, we expect four wells in the UK and Norway region this year, which Eric will come on to talk about. That’s Presto, which is currently drilling Lynghaug, Godalen and Chimera, total $25 million. The core part of the expenditure this year will be on the three out of the four wells we have planned in Mexico, with total net costs of $85 million. And then across the rest of the portfolio, we have data acquisition programs on some of the new positions we’ve acquired, for example, in Cote d’Ivoire and Suriname; as well as earlier-stage activity across the rest of the portfolio; and some pending new venture initiatives.
So overall, a very active capital program for the year with $300 million, one which is comfortably funded from our expected operating cash flows. And in addition, as I mentioned, we have substantial undrawn debt facilities.
So just to conclude on the key points. We’ve strengthened our balance sheet flexibility during the year by bringing Nova into the RBL facility and extending debt maturities. Whilst we have taken an accounting impairment on Kraken, those rebased assumptions are aligned with the production guidance we’d already given and are also aligned with the banking cases that were in place already, so we don’t expect any significant funding impact on the capacity on – sorry, any impact on our funding capacity from Kraken. It’s really just the accounting treatment of the rebased guidance we’d already given.
As mentioned, our capital commitment program for the year is roughly in line with operated cash flows expected during the period, and therefore we would expect net debt to remain stable through to the end of 2019. We’re working, as I mentioned, towards implementation of the project financing for the SNE development anticipated, with FID in the middle of this year. There and as well as across the rest of the asset base we continue to be active portfolio managers and, where appropriate, to maximize value and optimize capital allocation. We’ll continue to be active managers of the portfolio and asset base.
And on that note, I’ll hand over to Paul.
Many thanks, James. Good morning, everyone. I will start by giving you update on our two production assets and then move on to the positive progress we’ve seen regarding our developments before concluding on our preparedness for our 2019 exploration program, at which point I’ll hand over to Eric.
So the production has a story of two different halves, but overall across the two assets they are delivering our targets. Starting with Catcher. The reservoirs, wells, subsea and FPSO continued to outperform field development plan expectations. We had anticipated a field with 22 wells delivering 50,000 barrels of oil per day. And today, we are delivering 66,000 barrels of oil per day through the facility, with very strong uptime at well above 90% from 18 wells.
It’s early days in terms of assessing waterflood performance in these remobilized and injected sands, but we’ve incorporated a small upward revision of a few million barrels gross as part of our year-end reserves reporting process at the 2P or proved-plus-probable level. Equally important, the 1P or proved reserves on Catcher have grown 50% since FDP. And the 3P reserves reported in the FDP remain valid today. Satellite and infill opportunities are emerging, and we expect to high-grade the best opportunities for 2020, when a rig will return to drill a firm Varadero well.
Kraken has a slightly different story. However, we have a much clearer reservoir picture today than compared with six months ago. And reservoir voidage has started to improve, which was a significant issue during 2018. As we outlined in September, we conducted a program of reservoir surveillance and well testing across the existing 11 producers and 10 injectors, and we can now bracket the initial field performance at 18 months into three phases: water coning in a few select wells, resulting in initial higher water cut than expected for the field. This was followed by water breakthrough in other wells more consistent with expectation.
And over the last five to six months, we’ve seen increased stabilization, with the water cut essentially flat over this period. However, the increased level of water being produced from the field has resulted in us developing reliable history matches for our reservoir simulation models and generating new forecasts. And this process has unfortunately resulted in a downward revision of reserves on the field by approximately 19% as reported today.
Kraken last year produced around 30,000 barrels of oil a day. And this year, we estimate 30,000 to 35,000 barrels of oil per day, with an increase from the current levels of production expected when the DC4 wells, two new producers and one injector, come onstream. This will signal the end of the current joint venture-approved capital drilling program. Our main focus for 2019, therefore, relates to FPSO performance. And we are working with the operator, Enquest, and the contractor, Bumi, on short-and longer-term initiatives to improve both the uptime and the reliability of the facility.
If we move on to our developments then. Firstly, on to Nova in Norway. We are very much in the execution phase. Fabrication of templates, manifolds, umbilical and subsea trees is well underway on this $1.2 billion project. Final planning for the host platform Gjoa and for the shutdown associated with the Nova works is ongoing.
And the West Mira rig is on transit to Europe to allow it to complete its acknowledgment of compliance before it commences work on the Norwegian continental shelf. Initially, it’s likely to drill some exploration wells for Operator Wintershall before commencing the development program or development drilling next year for Nova. Recently, in February this year, we also saw the submission of two further satellite development plans, Duva and P1, tied back to the same host, to Gjoa, which when approved by the NPD are likely to have a positive impact on the Nova life and therefore economic field. So that’s good news for us moving forward and good news for utilization of existing infrastructure in Norway.
So next up is obviously the SNE field in Senegal. And during 2018, we made considerable progress on this 1.5 billion barrel oil and gas field. After extensive public consultation and technical review by the respective authorities, the Environmental and Social Impact Assessment of the planned development was approved in January.
The exploitation plan has also been technically approved, subject to finalization of the FEED studies and presentation of the final field development costs to the government. As you are aware, the subsea front-end engineering and design or FEED, as we call it, is with the Subsea Integration Alliance, Schlumberger, Cameron and Subsea seven. And the FPSO FEED is with MODEC, both well-established service providers in West Africa. We also anticipate complete award of the drilling contracts and the drilling services in the next couple of months.
And we anticipate that, with the incorporation of pricing from these contracts, along with the oil country tubular goods contract already awarded, in conjunction with a sharpened focus on well scope which you already have seen has gone from 26 wells to 23, will result in us being below our target CapEx of $3 billion for Phase one. These work streams running in parallel with the joint – ongoing joint venture project finance outlined by James position the project well for a final investment decision in mid-2019. As a brief reminder, the upper S400 and S500 reservoirs hold in aggregate 3.6 billion barrels of oil with around 500 million barrels expected to be produced over several phases of development.
At final investment decision, the operator expects to move around 230 million barrels gross into 2P reserves associated with the first phase. And further phases of oil development are anticipated to come onstream anywhere between two and four years after first oil to sustain the plateau production and to maximize recovery. Finally, our wells and supply chain team have also been busy during 2018 to position us as a company to execute our 2019 exploration program.
We believe that we can build on the strong HSE culture and performance, which during 2017 and 2018 was incident free across our operated wells program. We are pleased to have secured competitive pricing for the Transocean Arctic rig for Norway; the Maersk Developer for Mexico, which incidentally was Shell’s floating rig of the year in 2018; and Stena, whom we’ve worked closely with before, for the supply of Don for our high-impact well in the UK, Chimera. And on that exciting note and with the backdrop that our projects are progressing well, I’ll hand over to Eric.
Thank you, Paul. Good morning, everyone. As I’ve shared with you before, we continually work, and as Simon said, to high-grade our portfolio, looking for high-impact opportunities primarily in frontier and emerging plays. Our focus is always value, not simply geography, and we’re always mindful of the path to commercialization. Now towards the end of my presentation, I’ll touch on how we’re maturing some of the new plays we have entered, but my primary focus today is on our really exciting 2019 drilling program. As Simon and Paul said, this year, we’ll drill up to seven wells in three different countries, five of them operated. And that clearly demonstrates Cairn’s ability to operate effectively across multiple jurisdictions.
We expect to remain active drilling in Mexico, the UK and Norway into 2020 while we mature future targets in the balance of our portfolio. In Norway the Equinor-operated Presto well spud March 1st and, as I speak, is drilling ahead. It’s targeting Cretaceous sands which are stratigraphically trapped. And while it’s somewhat higher-risk strat play, as you can see, it is targeting very material volumes and more importantly has the potential to further derisk an emerging play where Cairn has similar prospects along trend in offset acreage.
We expect results of this well in early April. And then Lynghaug and Godalen in the Norwegian sea are both Cairn operated and will be drilled back-to-back in the second half of the year. And by drilling back-to-back, they share costs mobe-d, demobe-d; and therefore makes it a more efficient program overall. Lynghaug is testing Triassic sands, and Godalen Jurassic sands. And once again, a discovery on either will set up a new play trend inboard of existing production where Cairn has follow-on opportunities.
Then our attention will turn to the UK, where we’ll drill the Chimera prospect. And we recently welcomed Suncor as a partner in this block. Chimera is a stratigraphically trapped Heimdal sand target with a potential to be highly material to shareholders. And this prospect was identified in modern 3D data with state-of-the-art processing and was largely invisible on older vintages of data, so if successful, we’ve kind of identified a new play type in a very mature area.
And again, all of these prospects have the potential to be stand-alone developments, but the beauty of working in the mature areas in the North Sea and Norwegian Sea is even with more modest volumes they can be tied back to existing infrastructure. So our ranges of commerciality are much wider, which is one of the attractive things here. Then turning to Mexico.
I’m very pleased to be starting our drilling programs in both Blocks seven and nine, where we’re targeting a gross mean of over 500 million barrels of oil in a proven oil-prone basin and which actually remains underexplored. So we anticipate drilling two wells in Block nine this year, both operated by Cairn; and one well in Block seven where Eni operates. Drilling will commence in the second half of the year. And it’s good to point out that, of course, we’ve mentioned before the Zama well discovery which sits just east of our Block nine. And now the Murphy-operated well on the eastern edge of Block five has been reported today as a discovery. So good follow-through read-through for our activity. So if we look at the Alom prospect. This is targeting multiple tertiary shallow marine sands in what we call a typical upthrown fault block play. And we do see indications of direct hydrocarbon indicators on the seismic, which is always a risk reducer. And another attraction here, the Alom prospect happens to be in the shallowest water of any of our prospects in our portfolio at only 140 meters of water.
The Bitol prospect will be a deep well drilling over 5,000 meters of rock, and it will test all of the tertiary targets that have identified in the Sureste basin. So these are stacked targets. And we can assess all of them with one wellbore, which again is quite economical and effective. And this will be our deepest well in the 2019 campaign and will take roughly 60 days to drill. Now both Bitol and Alom are attractive targets, and both provide the capability again of being stand-alone developments. In Block seven the joint venture will still finalize the initial drill target, and we expect to have that imminently, but as you can see from this geo-seismic section there are multiple targets in the block, both faulted four-way closures as well as three-way closures up against salt. And that salt does make a very effective seal.
Prospect volumes are again quite healthy and well above the minimum required for development. We do anticipate another fairly deep well here with a depth of – again of about 5,000 meters and taking a couple of months to drill. And finally as you can see from the map, both here and in Block nine we have multiple prospects that have significant follow-on potential with success, either to be additional stand-alone developments or very lucrative tiebacks. So overall, we’re very excited to begin drilling in Mexico in this oil-prone basin. So I just want to leave you with we have a robust drilling program in 2019.
And we see it continuing into 2020, again, with a large operated component, which has always been one of our drivers. In our other leasehold, we continued to mature the target set. We acquired over 4,000 kilometers of 2D seismic in Block 61 offshore Suriname this January. We’ve already started to receive the first products; and they look very, very crisp and exciting. We plan to acquire 2D seismic with the operator Tullow onshore Cote d’Ivoire in the second half of this year. And we will commence a high-resolution 3D seismic survey over SNE field and the environs in Senegal. So this will provide more precise targeting for development wells. It will create a baseline for future what we call 4D seismic and will further mature potential other exploration targets. Now I’ll just say, 4D seismic, the way that works: Once a field – you have this baseline survey.
And once the field comes on production, you’re able to shoot additional seismic surveys which can help you identify bypass pay, so it becomes extremely valuable in later life in the field. So we’re quite excited for that as well. Offshore Ireland we have commenced a farm-down process there on our blocks, as we always knew we would after the acquisition and receipt of the new 3D seismic. And we’ve hosted multiple companies in our data room, and in fact, we’ve been approached by more companies that come in. And finally, we continue to look and high-grade other opportunities into our portfolio so that we’re always looking for the very best and highest-value opportunities. And that will continue both through 2019, 2020 and beyond. And with that, I’ll turn it back over to Simon.
Look. So in summary on the last slide. As you can see and as I think, hopefully, we’ve demonstrated, there’s multiple opportunities for value creation within what we believe is a sustainable business offering. On India, we will let you know as soon as we receive an update from the panel, but a key message is we remain absolutely confident of our position in the arbitration, and nothing has changed in that respect.
As Eric has just outlined, we’ve got a really exciting program of wells. We’re already on the first one. So we’re looking forward to reporting the outcome of that program to you during the course of the year. When you look at the portfolio management, mature developments. As Paul has outlined, our developments are moving forward well. They’re on track. And I think the key point to reiterate is that we are, have been and will continue to be active portfolio managers in respect of what we have currently within the portfolio of the business.
We, as Paul has mentioned, are very focused on delivering operational excellence. We’re operating five wells this year. We will seek to ensure that we have that continued track record of safe, disciplined, focused operation to continue that excellent record. And sustainable value creation. At the end of the day, as I said at the beginning, our mantra is to create, to add and to realize value for shareholders; and that is what we remain focused on doing. With that, I’d like to hand over for questions. Straightaway, Werner. I think there’s maybe a microphone, is there?
Q - Werner
Werner from Peel Hunt. Just to move straight to Kraken and the reserve downgrade. In your statement you cite three reasons. Two of them are above ground. One of them is belowground challenge. And it’s the belowground one which to my mind seems the most important, around increased water cut. So Paul, I was just wondering if you can elaborate a little bit more on the water cut issues, how many wells, what the percentage of water cut is; and whereas a world of variance lies between you and EnQuest, as to why you would as a non-operator take a very significant downgrade and impairment on your financials and they’re not. So what are the differences between you?
Yes, okay. Essentially, we’ll comment in two ways as – why we are taking the reserves downgrade and basically why we’re doing it now. So firstly, a little bit about so obviously heavy oil was quite different from light oil. And water was always expected in this field and in every well quite early on. So that, we should have that in our minds and mainly because it’s a viscous oil field. So the displacement of oil by water was always going to be less efficient than in a light oil field. So it’s very similar in that respect to Capitaine.
The facility has been built to handle, process, reinject the produced water. However, what is clear today is that the displacement of oil by water is not as efficient as we had originally expected in the field development plant, so consequently we are producing a level of water today which is higher than what we had in the FDP. Now so why have we actually decided to take a downgrade now? Is we said back in September, that we were going to carry out a program of reservoir surveillance and well testing.
The wells, both the production wells and the injection wells, are performing very strongly. So we’ve got continuous production from the whole length of the lateral – the horizontal section. We’ve got very good injection across the horizontal injectors. It’s a line drive. And that’s all performing really well. We’ve produced a meaningful volume of oil. So we produced 15.5 million barrels of oil from this field at the year-end 2018.
And we’ve updated and history matched. Our reservoir model was a generated new production forecast from them. And we know that we’re producing. Even if you take out the FPSO performance, we know we’re producing at an oil rate about 20% lower, below the FDP. So if we had readjusted for the poorer performance than we expected on the FPSO the surface or above ground, as you’ve described it, we might have produced 40,000 barrels of oil a day. That’s 20% lower than the target oil volume associated with the reserves in the FDP. And when we put all of those factors together, we believe at this time it’s a prudent move to readjust our reserves to reflect current performance and to do it now.
Has the field life been shortened, when we see your P date now?
No. I think – so the field life is not materially shortened. This was always going to be a situation where you’re going to be producing a lot of fluids, both oil and water, for quite a long period of time. That was the basis of the FDP. That was the basis of design. We’ve got a huge water-handling capacity built into the system and want to – we need to obviously get it performing a little bit better, but the longevity of the field hasn’t materially changed. So it’s more about sort of lowering the production levels over that period versus the original FDP.
Okay. And then just I mean just to understand the differences between you and EnQuest, why you’ve chosen to downgrade and they haven’t as operator, where the differences are between you…
Okay. So I mean I think it’s the – it’s probably best just to comment on what Cairn’s done. So each oil company will estimate their own reserves. And these obviously include the production forecasts that we’ve discussed, the oil price assumptions and obviously forecasts of operating and capital costs. And with our assumptions, which we believe are reasonable, we arrive at the P50 or the proved-plus-probable scenario that we’ve outlined today.
It’s Sasikanth from Morgan Stanley. Going back to Kraken again. You’re talking about production profiles. If you were to look beyond 2019 and into 2020 and a little bit beyond that, what – how do you see the profile going? Is it going to be stable? What’s the new peak? Is it around the 35,000 barrels per day? Or do you find it declining or remaining stable from 2019 levels?
Yes, okay. So I mean essentially, obviously, we’ve got three wells that we’re just in the process of drilling the rigs that they’ve got sort of last week or two at Kraken, the Transocean Leader. And we’ll have two new producers and one injector online. So obviously, with that new dry oil, we will obviously bring the rates up during 2019 higher than they’re producing today, but then obviously as we’ve seen in other wells, we expect that we’ll have water breakthrough as expected. And then basically there’ll be this gradual sort of build along the fractional flows so that the field will continue at low decline rates, to continue to produce but in decline for quite a period of time.
And I had a question on CapEx for 2019. Your $300 million excludes the post-FID Senegal costs, so I was just wondering whether there was a range on that. What could we expect for this year?
Yes. I mean we’ll give that guidance in conjunction with FID. I mean the number – so you’re right. The CapEx guidance we’ve given for Senegal for this year is all pre FID. So on taking FID, there will be additional CapEx in the balance of this year. I, we don’t expect that to be a huge number. Obviously, the bulk of activity will be in 2020 and 2021, leading through to first oil in 2022.
Good morning. It’s Michael Alsford from Citi. So just a couple of questions. On India, just to clarify: Obviously, you’ve given us new guidance on when you expect perhaps resolution. Can you just clarify? Is that what the panel has told you as when you should expect the outcome to be published, or is that your best estimate? And sort of like why then and not later or earlier would be helpful.
And then just secondly, on – and to James maybe, on the project financing for SNE, could you give a little bit more color as to how you’re looking to structure it? I guess, given of the fact of the funding from the government has put that perspective in terms of their share of the CapEx but also you’ve got smaller minority partners, how confident are you to be able to get to a project financing that will be fit for all concerned parties. Thank you.
I guess, on that first point, it’s driven by a lack of guidance from the panel and therefore, along with advisers, our view, given the amount of work that they have, of a kind of practicable estimation of time. But James, I don’t know if you want to touch any more on that.
Yes. So I mean, to directly answer your question: No, that’s not guidance that’s been given to us by the panel. As we said with the announcement yesterday, the panel has merely confirmed that they’re still not in a position to give a specific guidance as it were. So taking that into account, given where we are now in March; and taking into account what we – the advice we receive and what we know about the, I mean, commitments and so on, we really wanted to give some – our view on guidance that it’s not as imminent as expected.
And therefore, back end of the year is – or not before the back end of the year is our best estimate, but that’s our estimate, not the guidance we’ve been given. On project financing, as we’ve – as we guided previously, something around 50%, and so we’ll be targeting better than that, leverage on senior secured debt in a project financing facility for the joint venture is the target. The government clearly has the right and when we expect them to take up to increase their stake from 10% to 18% in the project.
And so there will be other sources of capital that partners, ourselves included, as well as the other non-operated partners will be accessing in order to fund the balance of the non-senior debt element, if you like. And there are a number of options which we are looking at ourselves and, I know, which other joint venture partners are looking at to fund the balance.
And when do you expect this to launch on the senior debt portion?
The senior debt portion, it’s been a – given the scale of the financing being relatively unprecedented in Senegal, it’s been a relatively long proprietary phase. As we mentioned, kind of earlier last year, we were kicking off the process. That proprietary phase is now pretty well advance. So it’s been both in terms of structuring and legal questions that arise in Senegal when we’re working with the joint venture group and the government of Senegal. Government of Senegal has been very actively engaged in this process. So that’s on the one side.
And then from sort of late last year, we’ve done a kind of market-testing launch, if you like, with a core group of expected lenders, ECAs and commercial banks in terms of capacity and initial feedback on a term sheet. We’ve now got that, which again is very positive feedback. And so we’re now getting ready to launch a formal banking case with a wider group of lenders. And on that, it’s really been about tying down a cost basis for that case, well-enough-defined cost basis for that case. And clearly where we are now with the awarded FEED contracts, we’re pretty much ready to go on that.
Yes. Hi, good morning. It’s Al Stanton, RBC. Couple of questions unrelated, one on Kraken and the other on portfolio management. Firstly, on Kraken, what is the partnership assumption about future CapEx? Is today’s reserve downgrade the assumption that CapEx finishes at the end of this year and there’s no further wells? And how does that view differ to what the operator might do or could afford to do? And then portfolio management: It seems to be selling at the moment.
If I had $1.6 billion or $1.4 billion coming back to me, I wouldn’t be issuing new shares any time particularly soon. So I’m wondering whether the overhang of the Indian arbitrage situation is preventing you from doing more material deals. Faroe is the obvious example, but is there something you should be doing that you can’t or won’t do while you wait for the money to come back from India?
Well, let me touch on that one first then. No, I guess, is the answer. I mean, as you know, five years ago when this hit us, we immediately discounted India from any future planning in the business. And as a result, what we see today is that kind of sustainable business offering. I mean, sure, if you have something that you believe is value accretive for shareholders and you have $1.4 billion alongside it, it gives you flexibility about how you might want to bring that into the portfolio, if you think there’s a good – if it’s the right transaction to do.
But if it’s the right transaction to do and it’s accretive and it’s the right thing for shareholders, then we don’t believe the lack of Indian money would stop us from finding a way to do it. The point is, though, in our view, which is why we haven’t done anything to date and – but we do look at stuff, it’s got to be accretive in the sense of what we currently have in our portfolio.
So we do consider things, but as I say, at the end of the day, it would have to be coming back to do we believe that and can we justify to shareholders that it’s the better thing to do than sticking with what we’ve currently got. So I don’t feel constrained, other than obviously it’s great if you have a lot of money sitting in your bank account. But if in that happy position, when it comes, just to reiterate, our desire is to make a significant return to shareholders.
Yes. So on Kraken, yes, I think it’s fair to say there are both infield and near-field opportunities at Kraken. The infield ones will be a function of further optimization associated with the flood pattern and understanding of that as to how to optimize it and potentially where best to place infilled wells. And particularly on the west side, so separate accumulations, are the new near-field opportunities. I mean essentially we are still maturing those, with a view that they could be 2020 opportunities.
Some of those wells could be drilled from existing infrastructure. There are spare slots on the manifolds. Some may require new infrastructure. None of that is yet committed because obviously the first or the initial field development plan program of capital has essentially – coming to a conclusion. And those resources that we’ve described there, we’d move into reserves potentially at the point that we sanction those investments.
And do you feel you’re on the same page as the operator in terms of the future [indiscernible]?
Yes, I think so. I mean I think we’ve got a common view on what the – those opportunities are and the time line to mature them and potentially the range of recoveries associated with those additional wells, but it’s still – I would say, still very much work in progress.
Questions? Back then.
Thank you. Chris Wheaton from Stifel. A few questions, if I may. First, to James, please, on the project finance. Would you expect to have to offer a parent company guarantee to get a project finance settled? Or would you assume that the securing of the debt against the project is sufficient guarantee for the lending banks? That’s my first question. I had a couple of follow-ups.
Yes, okay. So it will be – we anticipate that it will be a fairly typical project finance structure, i.e. that debt service, the repayment and the service of the debt, will be ring-fenced to the asset, secured on the asset; and in that sense non-recourse. Typically, the sponsors will provide a parent company guarantee, a completion guarantee, if you like, during the development phase. So the joint venture parties would typically sit there with some recourse for project execution, if you like, but then effectively repayment of the debt is non-recourse.
Okay, thank you. Would that include any additional spend you might have to cover for your partners? Picking up on Michael’s question about paying portion of the government share, for example.
Okay. The other question was on exploration, for Eric. What’s your actual commitment, committed exploration spend over 2019 and 2020? You’ve got an awful lot of activity going on. You’ve got some commitment to your – sorry, committed wells across 2019 and 2020. Could you tell me what the minimum commitment you’ve got in cash terms is over the next two years?
Well, this year, I mean, we’re sitting at $85 million Mexico; and $25 million net in Norway, UK. So that spells out 2019. 2020, say up to another seven wells. So one of those will be in Mexico. The majority will be Norway and possibly UK. So I can’t give you a firm number. It’ll be less because Mexico will be less. And Norway is post-tax cheaper. So it’ll be something in that range but, I would expect, a little bit less than 2020, but you never know because, as we say, we constantly look to optimize our portfolio. So if other things come in and they make sense and we can afford them, as Simon said, we’ll – if they’re accretive, we’ll make – we’ll figure out how to do them. But I suspect it won’t be overly dissimilar.
Super, thank you.
Hi, It’s James Hosie from Barclays. Another question on the project financing for Senegal. Can I just clarify? You talk about 50% debt funded. Would you be able to draw 50 – or draw down 50% of the costs from day one, or with the equity share of the spend which are front-end loaded?
The – sorry. Your question is about the drawings under the facility. Or…
Yes. So when you start drawing on the facility, will you be able to draw on the facility for 50% of development costs from day one? Or will you have to basically put the equity component upfront into the development spend?
Well, it – there are points about the term sheet that I wouldn’t want to negotiate live on this line, but clearly we will at the point of taking FID need a – need to be in a position, for ourselves as much as for the banks, with a very clear picture of what the overall funding plan is for our stake, yes.
Yes. And with – on your reserve-based lending facility, will SNE always be excluded from that given it’s going to be funded from project finance?
No. The RBL – the capacity under the RBL facility is now available to draw for general corporate purposes, so we’re not constrained on what we draw that for.
But the RBL facility size, is that independent of SNE?
Oh, I see. So yes, the RBL facility has three borrowing-based assets in it: Catcher, Kraken and Nova. And we’re putting together a separate financing for SNE, but we can draw under the North Sea facility to fund any part of the portfolio.
Hi, It’s Alwyn Thomas here from Exane. Just actually to follow up on SNE. Are you still looking at potentially farming-down the asset? Is that still a consideration as a separate process from the project financing? Or are you happy with the current equity stake post government dilution?
Yes. We – look, I mean, I think we’ve said this before. We’re happy with the current stake. And we’ve certainly designed it so that we can move forward with the current stake right away through the development, but at the same token and when people have asked us that before – so we’ll look – at around FID, we may, depending on everything else, look at some selling-down some of that stake. I mean I think the important thing is we will be staying in Senegal.
We’ve got a commitment to that project. We think it’s a very attractive project, but obviously depending on what the market looks like, if there’s a kind of an attractive offer sitting in front of us and it’s something we want to redeploy, then we’ll think about it. But we’ve designed it so we can stay at the current equity level if we want to.
Okay. Thank you.
Thanks. It’s James Thompson from JPMorgan. Just a couple of questions, if I may. Just coming back to India. Obviously, you – the arbitration panel has sort of said they’re not ready to give you some guidance, so what’s brought you to the kind of end-2019 kind of estimate? What are the sort of details behind it that have led you to that decision? What do you think is the variance around that? Because obviously it’s a very big event. The market is looking for some sort of confidence around it, so some sort of guidance there would be helpful.
Yes, yes. I mean, as we set out in the sort of account of the history in the announcement yesterday, when the main merit hearings were originally scheduled for August of last year, the panel indicated to us that, the whole process having been reasonably protected by then, they would seek to issue the award as expeditiously as possible after those hearings. So I mean that’s, frankly speaking, the only guidance they’ve ever – that we’ve received. They’re not obliged to give us any guidance at all.
So on that basis, we clearly expected that they would be able to make progress, significant progress, on the award during the second half of next year. What – sorry, of last year. What’s become clearer at the end of last year and again just over last weekend in correspondence with the tribunal is that, because of the number of procedural matters that have been brought before them since last August, they have spent a significant amount of time ruling on those and dealing with those and significantly less time progressing the award.
So we don’t know where they are with the award, but we know that they’re significantly less progressed than they’d hoped to be. And we also know that they’re busy arbitrators with other tribunals coming up in front of them and so on, so when we take advice on the matter, taking all that into account, our best estimate is that it’s not going to be before the back end of this year.
Okay, thanks. And then just moving to exploration. In terms of Mexico, what are the kind of main risks here? I mean these are pretty deep, and they look relatively complicated wells. So just to understand a little bit more about some of the uncertainties.
Yes. The main risk, obviously, overall it’s the lack of penetrations. I mean there aren’t a whole host of wells in the immediate vicinity to look to for reservoir properties, et cetera, but the ones that we have, have kept us confident that, down to the depths we’re looking at, we’ll have good producible reservoir. I mean it’s an oily basin, so source and maturity is not an issue. Hydrocarbon migration is always a question, and then seal. As I showed, some of these are fault traps.
So fault seal, though you can estimate it, until you drill the well, you never know for sure. So we’re quite encouraged by source rock, which is one of the key elements you know the hydrocarbons are there. We see migration into the most of the prospects that have been drilled to date, and the wells that we have access to have shown reasonable reservoir.
So one last, quick question because we’re up against time’s up.
So I’ll be quick. Just following on, on the India thing. Going forward, what is now the process? I mean, do we sort of wait until the back end of this year and then you get an update and maybe it’s summer 2020? Or will you be sort of requesting updates on a quarterly basis to see if you can get more visibility?
As I said, the tribunal haven’t given us specific guidance on when they expect to issue the award because they don’t feel they’re in a position to give us that guidance at that point. They have committed to update us with regard to their progress. That’s a fairly clear position they’ve stated to us over last weekend, which we announced yesterday. So there probably isn’t much merit in us continuously writing to them, asking if there’s an update, but obviously we’re confident that they’ll update us when they can.
Okay, I think that’s it. Thanks very much indeed for your time. We look forward to reporting progress through the year. Thank you.