Half Year 2016 Cairn Energy PLC Earnings Call

Aug 16, 2016 AM EDT
CNE.L - Cairn Energy PLC
Half Year 2016 Cairn Energy PLC Earnings Call
Aug 16, 2016 / 08:00AM GMT 

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Corporate Participants
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   *  Simon Thomson
      Cairn Energy PLC - CEO
   *  James Smith
      Cairn Energy PLC - CFO
   *  Richard Heaton
      Cairn Energy PLC - Exploration Director
   *  Paul Mayland
      Cairn Energy PLC - COO

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Conference Call Participants
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   *  Daniel Ekstein
      UBS - Analyst
   *  Nathan Piper
      RBC - Analyst
   *  Michael Alsford
      Citigroup - Analyst
   *  Mark Wilson
      Jefferies - Analyst
   *  Stephane Foucaud
      First Energy - Analyst
   *  Russell Camms
      Standard Chartered - Analyst
   *  Robin Haworth
      Stifel - Analyst
   *  David Round
      BMO Capital Markets - Analyst
   *  David Mirzai
      Deutsche Bank - Analyst
   *  Anish Kapadia
      Tudor Pickering Holt - Analyst
   *  Caren Crowley
      Davy Research - Analyst

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Presentation
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 Simon Thomson,  Cairn Energy PLC - CEO   [1]
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 Okay. Good morning everybody. Welcome to Cairn's half yearly results presentation. I'm Simon Thomson, Chief Executive. With me are James Smith, CFO, Richard Heaton, Exploration Director and Paul Mayland, COO.

 So, as in the usual way, we've got a presentation to run through with you this morning and we'd be very happy to take questions at the end. It is being webcast so although it's quite a small room and we can all hear each other, there will be microphones to ask a question and please do state your name before asking the question.

 Cairn's strategy is to deliver value for shareholders from a balanced E&P portfolio. To do that, we seek to create significant growth opportunities within a portfolio that is both sustainable and self-funding. Within that portfolio we've got exposure to material discoveries and prospectivity, principally in Africa and Northwest Europe, and those interests are held at appropriate equity levels for the size and scale of the company that we are.

 Our UK developments are progressing on track and under budget and will deliver significant production for us from 2017 onwards. And, as you will have seen from today's announcement, we have established a substantial and growing resource base. And it's worth noting that our net combined 2C and 2P resources now total in excess of 0.25 billion barrels of oil equivalent.

 As a company we'll continue to focus on value creation and monetization, but that's linked with the successful track record of HSE and corporate responsibility, and that latter point is very important for us in respect of a calling card with both host governments and partners alike as we assess additional new venture opportunities to add into the portfolio.

 And we have commitment to continued delivery of value from discovery and development, including potential further returns to shareholders, and that's in line with a consistent strategy of creating, adding and ultimately realizing value for shareholders through monetization.

 So a few words on Senegal, where a safe and successful appraisal drilling campaign has confirmed the world class nature of the SNE field. Paul and Richard will come on and talk about the detail but in summary we're delighted with what we have proven up thus far and also with the additional potential that we see, not only in SNE but also in the surrounding acreage position.

 The resource base continues to increase and today we've announced a significant upgrade in our contingent resource estimates. So the SNE 2C STOIIP is in excess of 2.7 billion barrels, and that's with current gross recoverable resources now standing and revised to at the 1C level 274 million barrels, at the 2C 473 million and at the 3C in excess of 900 million barrels. And for the sake of comparison, at the 2C, as you know, the previous guidance was 385 million barrels, so a significant increase.

 And in addition, we still see in excess of 0.5 billion barrels of risked resource upside and right now we're working on the exploration prospectivity to finalize prospects for consideration in the next phase of drilling. And Richard will talk about a couple of those exploration prospects in his section of the presentation.

 As Paul will outline, development planning is underway. We believe we're well placed to benefit from cost deflation and also project optimization, and that in turn has a very positive knock-on effect to our economics, as James will outline.

 And the third phase of the E&A drilling is scheduled to commence at the turn of the year and again we are benefiting significantly from reduced costs, both in respect of rig and also associated services.

 So in summary, we see continued delivery of value from Senegal, through a combination of increased costs -- sorry, reduced costs, increased resources and also near term activity that will access in our eyes significant potential upside. So there's a lot still to go in Senegal. James?

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 James Smith,  Cairn Energy PLC - CFO   [2]
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 Thank you Simon. Good morning everyone. So in the next few slides I'll go through the cash flows for the first half, the current funding position and an update on our future capital investment plans. And as you'll see, the focus remains very much on capital discipline to continue to ensure that we retain the flexibility to direct investment to the assets where they'll deliver the best returns.

 And for us today that's really about two key areas. The first is completion of the Catcher and Kraken projects to deliver sustainable cash flow from next year and that's -- those barrels are with an all-in average production cost of $17 a barrel at plateau. And the second, as we'll spend most of our time today talking about, is further derisking of Senegal, and that's really an asset that's delivering on our principal strategic goal as a company, which is about material low cost resource bases within large acreage positions.

 Beyond that investment plans are really about earlier stage exploration activity across the rest of the portfolio and continuing to access the opportunities to enter into low cost new business development opportunities.

 So this slide just takes you through the first half cash flows. As you can see, $603 million was the opening cash position. Principal expenditure during the period was on the four-well Senegal appraisal and exploration program and on the Kraken development project. During the first half and actually as of today we continue to be fully carried with respect to the Catcher project, so that's why there are no cash outflows there. So all of that together with relatively low activity across the rest of the portfolio or low capital investment across the rest of the portfolio, I should say, and a continuing low G&A expenditure with debt remaining undrawn, that took us to a cash position at June 30 of $414 million.

 So taking that forward, the next slide sets out the current sources of capital available to the Group over this year and next year. On the left-hand side and on the right-hand side the expected or committed and planned uses of that capital, again over the period between now and the end of 2017 which will deliver us into free cash flow in the North Sea.

 So starting on the left, $414 million opening cash position. That together with a Norwegian tax receivable, effectively cash, takes us to cash resources for the Group of roughly $460 million, and in addition to that we expect to be able to draw up to $260 million between now and the end of next year on the reserve base lending facility that we put in place to fund the North Sea development project.

 Clearly next year we'll also be moving into operating cash flow phase in the North Sea, first of all in Kraken and towards the end of the year we expect on Catcher. There's some guidance there in the box of what we would expect operating cash flow to be from Kraken, ramping up in the second quarter of next year towards peak. Even at $45 oil representing the forward curve, that would be around about $100 million of operating cash flow next year.

 So all of that together is about $800 million or so of existing funding available to the Group between now and the end of next year. If we look out beyond that in terms of the operating cash flow, as I said, all-in production cost for Catcher and Kraken of $17 a barrel, significant tax shelter, means that even at today's oil price in the mid $40s we'll be generating around about $250 million of operating cash flow at plateau production or at $65 Brent, for illustration, about $400 million of operating cash flow.

 On the right-hand side you can see the committed -- starting with the committed uses of CapEx and moving into what we plan for further in Senegal. $45 million of working capital, effectively activity undertaken in the first half where cash flow out has been post June 30. $315 million represents the total development CapEx for Catcher and Kraken net of the carries in favor of Cairn between now and the end of 2017. And you can see there the split between the two assets and the phasing between this year and next.

 Committed as of today exploration and appraisal activity $55 million which represents ongoing activity in Senegal plus relatively low commitments across the rest of the portfolio. And then the next two blocks there represent I guess what we see as being still currently under planning phase but the expected minimum activity in Senegal in 2017. So that's two appraisal wells with one or both of them having relatively full testing program and pre-development study work ongoing on the asset. So that totaling around about $80 million.

 As Paul and Richard will come on to say, 2017 is going to be a key year for Senegal in terms of moving it towards a development concept decision and submission of a development plan in 2018 and 2019. So clearly there is the potential for that program in Senegal to expand well beyond those two wells that we're envisaging as being the firm program.

 Last point on funding, I guess none of these plans includes a resolution of the ongoing dispute in India with regard to the retrospective tax application to our internal reorganization in 2006. That was a $1 billion asset that was taken away from us in 2014 for which we're seeking full compensation through the India -- through the international arbitration process. That process is now well underway. We submitted our full statement of claim to the arbitration panel earlier this year and the arbitration panel has asked India to respond in full before the end of this year. So on that basis we'd expect to move to hearings in the first half of 2017 and a ruling thereafter. So as I said, none of that included here but clearly we are expecting a positive outcome on that.

 Next two slides provide an update on the two UK development projects, and really it's a similar story in some ways across both of them, development drilling running ahead of schedule, subsea installation in the North Sea completed on Kraken and expected to complete by year end on Catcher. For both of them their critical path item to getting to first oil is really around FPSO construction, and you can see here the Kraken vessel in Singapore with all of the modules now lifted on and sail-away expected in Q4 of this year.

 On Catcher, you'll recall we guided the market that there had been a bottleneck in the hull construction in the yard in Japan. The mitigation plan which the partnership has put in place to address that has now been effected, and you can see here the complete hull -- the complete vessel joined together in Singapore awaiting the modules to be lifted on top. And that keeps us on track for expected first oil in 2017.

 The story across both of those development projects as well as across the rest of the portfolio has been one of benefiting from I guess the flipside of the lower oil price environment, which is an improved cost and contracting environment.

 So you can see here, we've been very active in managing our capital program and our project costs over the last 12 months. Starting on the left-hand side, the first two points together, we have deferred around about $80 million of previous exploration commitments where they didn't make sense as investments in the current oil price environment. Where we have been exploring here in the UK and Norway, that activity has come in around $40 million below the original budget.

 There isn't a block on this chart here for it but it's also worth remembering that in the first half of this year we undertook a four-well appraisal program in Senegal for the same cost as had originally been budgeted for three wells. And then here you can see the most significant blocks on this chart in terms of CapEx savings are across the two development projects.

 So together across Catcher and Kraken net to Cairn savings between now and the end of 2017 of around about $160 million, and we're continuing to work on initiatives with the operators on those projects so we expect more to come.

 So all of that, net of having taken on more equity in the Kraken project, means that we have deferred or reduced $226 million of CapEx to the end of 2017 over the last 12 months.

 Onto the asset where we're expecting to have the optionality to deliver the most value from the current cost environment, and that's in Senegal. This slide provides an update on the development scenario and associated costs for an SNE 2C development. It's a chart in the same format that you'll find back in our Capital Markets Day in May 2015 but with some important revisions to that.

 We had previously guided for full development CapEx per barrel of around about $20 based on analog fields and similar water depths for FPSO developments. But based on the improved contracting environment today, but also importantly our experience of drilling five wells into the reservoir so far, we're updating today that guidance with reductions of 25% to 30%. So we see sub $15 a barrel all-in development CapEx for a field of the 2C size that we've guided to.

 This assumes a leased FPSO development, so you can see the bulk of the CapEx there is really in development drilling and subsea installation. So the good thing about that is it means that most of that CapEx is back-ended towards first oil, which clearly enhances the economics in the financing plan for a development of that type.

 Operating costs associated with that development scenario, $8 to $10 a barrel, and that includes an FPSO lease cost assumption in there.

 And again on timing, the guidance remains the same. So with the development recommendation in 2018 and FID in 2019 we'd expect first oil to be in the window 2021 to 2023.

 The next slide here sets out the economic outputs of that development scenario if you like with NPVs per barrel at various oil prices and unlevered project IRRs at those same oil prices. You can see there with the dotted yellow lines, which represent the guidance we gave back in May 2015, that that results in a pretty significant upgrade both in terms of value and project returns from the previous guidance. And as you can see, pretty healthy returns even at today's oil prices and we think reaching a threshold 10% return in the low $30s Brent.

 Clearly these are economics for the 2C standalone development of an SNE field scenario but as Richard will come on to talk about, there's significant resource upside potential in the blocks. So exploration success near to that field could clearly be developed at relatively low cost as a tieback to the central development.

 I guess finally on SNE economics, this slide here sets out the results of that development plan in the context of breakeven oil prices for other projects globally. It's taken from the Goldman Sachs study of upstream -- international upstream projects which we've screened for development phase projects.

 And you can see, SNE ranks extremely highly on that list in terms of its ability to attract industry capital. And as Paul will come on to outline in a bit detail, whilst SNE is nominally a deep water development, the operating environment, the geological characteristics and the fiscal terms altogether combine to mean that it actually ranks above many shallow water or shallower water development projects and even some onshore ones in terms of its economic attractiveness.

 So in summary, before I hand over to Richard to talk in some more detail, the focus has been very much on capital discipline to make sure that we have an investment strategy that's very, very focused on assets that deliver returns in a lower oil price environment.

 And as a result of that, we're very well positioned to deliver the business into cash flow phase next year and to support from the current balance sheet our continued investment in the Senegal asset, whilst in the background continuing to build the portfolio opportunity set in the background. And on that note, I'll hand over to Richard.

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 Richard Heaton,  Cairn Energy PLC - Exploration Director   [3]
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 Thanks James and good morning everyone. First of all, just a brief reminder of Senegal. Two years ago we still hadn't made our discoveries in Senegal, so we've made a tremendous amount of progress since then, six wells now drilled. And you'll see that essentially the first two wells, both were discoveries, they were both the first wells ever drilled in the deep water offshore Senegal and the first two oil discoveries of any size in Senegal as well.

 We focused our attention since nearly wholly on the SNE area, it's shallower water, the reservoirs are better quality there, and that is really where the bulk of our effort has been to date.

 What's new today is that we're announcing an upgrade in the resources that we see in that field, and also giving the detailed figures out on the very large in-place oil that there is in the field. We have a very large area in the license and I'll be talking about the exploration potential there as well.

 So the next slide really talks about the results of those wells that we've now drilled. We've had a very successful and safe campaign to appraise the SNE field. We now have five penetrations across that field, roughly nine kilometers in a north-south line and about five kilometers from east to west, right in the central portion of the field. The field during that time, as we've proven with these wells now, has increased in size. And at the very top seal, the area of the field is over 350 square kilometers. And we have across that area now, as far as we can see, there's a very consistent 100 meter gross oil column there with a gas cap above it in the center of the field.

 We can see that everywhere we drill those five wells we have good quality reservoirs and better than perhaps one would normally predict in these age of rocks and type of rocks, but it's very consistent. And shown on here just one of the reservoir layers in the upper levels of the reservoir. Right across the field we always find sands, we always find them of good quality. We can actually tie them very accurately on the seismic data. We have new seismic data and reprocessed seismic data now that ties very well across the field, and we can use the amplitudes from the seismic data as shown on that little map to almost differentiate between where there's gas, where there's oil and water, and some of the internal features of the rocks there.

 We've recovered a huge amount of core data. Every bit of core that we try to capture we recover back to the surface. We have 600 meters of rock in laboratories in Aberdeen and elsewhere being analyzed. It allows us to really characterize the reservoirs of the field very, very accurately. Now that work takes a long time to complete; it's a huge amount of data. We integrate that with all the log data that we've got from these wells as well. It's a fabulous database to work with and we're still working through it.

 What that means is we are able to confirm a great deal more certainty now about the field. We've got great information that allows us to understand how it's put together. And essentially, as we said -- we saw in SNE-1 the reservoirs are best at the bottom and then we have lower reservoirs above that, the finer grained and slightly thinner reservoirs above that. We've got good test results out of both though, the lower reservoirs 8000 barrels a day out of one test and in the upper reservoirs 5000 barrels a day. Those are great test results for anywhere, some of the better ones that you'll see along the West African margin.

 In the test that flowed 5000 barrels a day from the upper reservoirs there's some slight pressure depletion which shows that the connectivity there is not quite as good as in the lower reservoirs, and that will be a feature of trying to understand that uncertainty when we come to the next phase of appraisal.

 So the resource base is hugely improving as we go through. For the first time here giving the figures on where we were at March with the associated in-place oil, the STOIIP, and today's estimates are independent estimates given by ERC-Equipoise, demonstrating, if you like, the consistency between our own and an independent auditor's view.

 We've now got over 2.7 billion barrels in place at the 2C level and a recoverable resource out of that of 473 million barrels. And you can see it's a wide range. These are probabilistic estimates; this is trying to take into account still the very large variation there is in the field because we're still really at the relatively early stages, only 18 months after discovery, of trying to piece together what is now a very large field.

 But it's a great story. What we will be doing with the next wells is trying to understand better the connectivity and make a yet more informed decision about how best to develop the field and what sort of field development plan to put in place, and Paul will go on to explain some more of that.

 Not only is there obviously a good field but we went into this area because if you did find hydrocarbons, there's a great upside story here. There's lots of different plays to go for; there is an exploration potential around it which we can tie back to a main project. And we have -- we're working that data now, integrating the new well data with the new seismic data, and coming up with more detailed exploration prospectivity which we will incorporate into the next drilling plans.

 Paul will give more detail on the actual drilling plans a little bit, but essentially I'll just give some details on two of the prospects, one in the shelf area and one in the deeper water area now. Altogether we estimate there's probably another 500 million barrels of mean risked resource in those prospects to go. So you add that together with almost 500 million barrels in the SNE field and the block potential, still 1 billion barrels, which is the guidance that we've continued to give.

 So the Sirius prospect we've talked about before. This is on the shelf; it's just to the north of SNE, it's at the same reservoir levels. We can separate it out at some of the upper reservoirs here within SNE. We see this as relatively low risk. It's a stacked field, as we now know from SNE is the case, probably around about 80 million barrels, just over 80 million barrels when you consolidate those in the prospect, but a very high chance of success based on what we see in SNE. So 67% chance of success. This could be a very attractive tie-in prospect.

 And if we go to the basin, you'll see the FAN well in there to the north. That found a very large column of oil, over 500 meters altogether of oil-soaked rock. But the reservoir quality in there, it's quite deeply buried, not so good.

 Further to the south, there's a prospect here that we're looking at which is much shallower. We can see the feeder sandstones coming in from the shelf, from the field, SNE field. We do hope that the reservoir quality here might be better. At just one layer in this prospect, we have about 150 million barrels mean prospect resource in here with about a 15% chance of success. It is a stratigraphic prospect, stratigraphic trap. That does work at FAN, it could well work here. Again, it would make a very attractive tie-in.

 Now all this work is still very much ongoing, integrating all the new data from SNE and the new seismic. We haven't made decisions firmly yet on which wells we'll be drilling as part of an exploration program. That is still yet to come.

 And at this point I'll pass on to Paul to take us through the next stages of the operations.

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 Paul Mayland,  Cairn Energy PLC - COO   [4]
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 Thanks Richard. Good morning ladies and gentlemen. As already mentioned, we intend to move to a third phase of drilling offshore Senegal commencing towards the end of this year. And we aim to build and indeed improve upon the good HSSE performance that we achieved during 2015 and 2016.

 The proposed program is anchored around two firm wells plus multiple one well options, and both semi-submersibles and drill ships are under evaluation for what has already proven to be a very sought after contract.

 There are a number of objectives to be addressed in this program, including testing certain reservoirs that otherwise have not yet been tested, and interference testing between wells. This was always part of the joint venture's appraisal strategy, reflected by the fact that we've installed pressure monitoring gauges in two of the existing four appraisal wells. And as Richard's also alluded to, exploration opportunities are also likely to form part of the program.

 In parallel with the earlier appraisal drilling, we've remained conscious of the expected journey through appraisal and development planning and the requirements ultimately for a final investment decision to deliver oil production offshore Senegal. We've completed a highly successful second phase of drilling, primarily focused on the SNE appraisal, and that, as Richard has outlined, has provided us with an excellent data set.

 Further appraisal activity is focused on improving the definition of the project, in particular related to water flood planning of the upper reservoirs, which ultimately influences the number of drill centers and their location and the number, location, offset and orientation of production and injection wells to be drilled on the field.

 The concept that we've previously outlined, a floating production storage and offloading vessel with subsea wells, remains valid, and the 2C resources presented today guides us now to a plateau rate of between 100,000 and 120,000 barrels of oil per day.

 I think everyone is familiar from the Capital Markets of last year with the timeline shown at the bottom of the page. I think that illustrates the remarkable progress the joint venture has made in only 18 months since discovery and the considerable effort that we will undertake together over the next 18 to 24 months to allow us to submit an exploitation plan in the first half of 2018.

 On this slide you can see a diagram which outlines a range of offshore projects versus water depth, taking us all the way out on the right-hand side to the current technology limit for deep water of around 3000 meters. SNE obviously sits very comfortably within this window and is classified as a deep water discovery, being located in approximately 1000 meters to 1200 meters of water.

 Indeed, it is worth noting that the SNE reservoir depths are actually less than the water depths alone in other global ultra-deep water discoveries in the Gulf of Mexico and indeed close by in Africa.

 Also shown on the diagram on the left are our two non-operated UK projects, Catcher and Kraken, and these have given us excellent insight into the service contractors, their performance on the projects and their differentiating characteristics. They've also allowed us to sharpen our views on contract strategy and models for execution, particularly at this interesting time in the industry, which we will inevitably, along with our other joint venture partners, clearly discuss and seek to apply in Senegal.

 So moving on to the next slide in terms of development conceptual engineering. We've initiated pre-engineering studies with an established engineering house and we've outlined the initial preliminary reservoir and wells bases of design. We've also installed a metocean buoy this summer offshore Senegal to gather further data in respect of optimizing facility design.

 And overall we believe this project is very well placed, being at the concept select stage, to now benefit from project optimization, cost deflation and further standardization, because although there's some CO2 in the gas stream, the reservoir conditions and fluid conditions are otherwise relatively benign, and this will allow us to utilize existing standard oilfield equipment. And because of the scope and phasing of the project, it is expected that this will be very much on the radar of the usual service providers.

 Onto the next slide in terms of conceptual development well planning. In addition to preparing for the next phase of drilling, as illustrated in the photo of our new pipe yard in Dakar, the wells team have been working together with the joint venture, completing initial studies in respect of conceptual development wells.

 We believe that around 15 wells to 20 wells will be drilled prior to first oil as part of a multi-year ongoing development drilling campaign which will comprise oil producers, water injectors and gas injectors. And approximately two-thirds or so will target the upper reservoirs with the remainder targeting the lower reservoirs.

 A variety of well types are being investigated but most are ultimately of a near horizontal or high angle type with lateral sections of around 1500 meters in the reservoir, and may or may not include some form of intelligent completion.

 On average we believe that the well costs have reduced by around 25% from our previous estimates, and this has been carried forward in the economics presented by James earlier.

 So in summary, we're making good progress in terms of commencing another exciting phase of exploration and appraisal drilling, anchored around the SNE discovery, and we expect to start that campaign and operations before the end of the year. We believe that this particular project is well placed to benefit from further optimization, cost deflation and standardization and we remain on track to submit an exploitation plan during 2018.

 I will now hand back to Richard, who will describe our exploration initiatives elsewhere in our portfolio and our ongoing new venture activity.

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 Richard Heaton,  Cairn Energy PLC - Exploration Director   [5]
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 Thank you Paul. As Simon pointed out in his introduction, we have a balanced portfolio. And as well as the Senegal story, we have an interesting and building portfolio in the UK and Norway. Of course we've talked about the two development projects, but our exploration plans in the UK tend to be centered around those fields. And if we go to Norway, where we have the Skarfjell discovery in 2012, we have a focused exploration portfolio around that area too where our expertise can be, if you like, honed. And we also have a building position in some of the less well explored parts of the Norwegian Sea and the Barents Sea where we share [the MPD's] view that with just 100 wells drilled to date there's a considerable yet to find potential in that basin.

 We've taken operatorship in Norway over the past year and we now have some operated licenses. That gives us greater control. And we're making sure that this portfolio on its own is a balanced portfolio with a good deal of activity in the coming years.

 Beyond that of course we have to continue to look at new ventures. The current market state means that it's probably a good time for an acreage reload and refresh the portfolio, but we're looking for those options where we can get in at relatively low cost. We see those, quite a number of them at the moment. And we're very focused on making sure that we access the best of them, focusing first of all along the Atlantic margin, where we do have some technical and expertise and knowledge. But it's a great time to be trying to do this and we hope to bring some new news over the coming years on this.

 At that point, I shall pass back to Simon to summarize.

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 Simon Thomson,  Cairn Energy PLC - CEO   [6]
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 Thanks, Richard. So in summary, we continue to offer significant growth opportunities within a balanced portfolio. We've got a material and growing resource space in Senegal, as you've seen, and we've got further near-term drilling activity to access upside that is also benefiting from a lower cost environment.

 Got balance sheet strength and we've got substantial cash flow from near-term production from Kraken and Catcher in 2017.

 And the Company continues to focus on value creation and monetization of success, as you see from a familiar diagram on the right. That continues the long-term strategy of creating, adding and ultimately realizing value for shareholders.

 With that, I'd like to hand over for questions.

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Questions and Answers
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 Daniel Ekstein,  UBS - Analyst   [1]
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 Thank you. Daniel Ekstein from UBS. I've got two questions, both on Senegal. Firstly, thanks for the oil-in-place figure, that's helpful. Is it possible to give an indication of the split of recovery factors between the lower reservoirs and the upper ones? Taken in aggregate at the moment, it looks like quite an undemanding about 18% or so, but I expect there's quite a wide variance there.

 And then secondly, just on the timeline you laid out for development in Senegal, is that something that the government is comfortable with in terms of time to first oil? And secondly, is there any indication on introduction of local content requirements? Thanks.

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 Simon Thomson,  Cairn Energy PLC - CEO   [2]
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 Yes. I think -- let me answer the second part of your question first. Yes, the government's absolutely onboard with that timeframe. And indeed, when we submitted appraisal plan with the joint venture last year in relation -- tied to the three-year extension on the license, all those timeframes were agreed with the government.

 And local content I think is included in the production-sharing contract from the point of view of what we can do, but I don't know if there's any further detail than that.

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 James Smith,  Cairn Energy PLC - CFO   [3]
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 Yes. There are no particularly onerous provisions in the PSE, as you may have seen in some other jurisdictions. But clearly we work to include as much -- well, we already are working to include as much local content and local training as possible.

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 Simon Thomson,  Cairn Energy PLC - CEO   [4]
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 Richard, do you want to --?

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 Richard Heaton,  Cairn Energy PLC - Exploration Director   [5]
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 Yes. Obviously the lower reservoirs do have higher recovery factors. In fact, the upper reservoirs, there are many layers in those. Some of those we expect to be able to water flood. Others may ultimately simply be depletion production on some layers. In fact, that's obviously where the upside lies within the range of volumes that we have. And that is essentially what the focus of much of the appraisal, the next phase of appraisal, is going to be.

 So for us to be able to find out answers to those is really the aim there. So it's a little bit early to give out specifics, but essentially the lower ones, as you point out, will have better recovery factors.

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 Simon Thomson,  Cairn Energy PLC - CEO   [6]
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 Next.

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 Nathan Piper,  RBC - Analyst   [7]
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 Good morning. Nathan Piper from RBC. I wonder if you could just clear up a couple of things first off. So Woodside's obviously taken or looks to be completing the deal with Conoco. Can you clear up if there is a pre-emption and if you're interested in that? And also, with the change in participant, does it put more emphasis on you to operate the project when it moves into the development phase?

 And then secondly, on the drilling plan, so you've got two front wells which are -- sound like they're going to be appraisal wells. And the pace of exploration in the wider portfolio, is that also -- is the Senegal government happy with that? And are you going to -- is it more likely than not that you do two to four wells this year?

 And maybe the last one, if I can, a slightly different point here, you were talking about the breakeven of the project. Given that oil price is $45 today, would you FID this project at this oil price?

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 Simon Thomson,  Cairn Energy PLC - CEO   [8]
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 Yes, but I'll let James come back to the detail on that. But on your Woodside question, we've confirmed to Conoco that we are supportive of Woodside coming into the joint venture. From our perspective, we think they'd actually be a value-adding partner for us. If you look at their exposure to equity interests, Nova Scotia, Ireland, Northwest Africa, there's actually quite a lot of alignment with the way that we look at the world as well.

 So we're very supportive of them coming in actually and we're very supportive of the original principle. They have a lot of offshore deep-water operated experience and therefore we think -- we see no reason why the original tension for us to provide an option for somebody to take on that operatorship at the time of development still stands. So that would still be the case, as it has been with Conoco.

 Sorry, there was another part to your multifaceted question.

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 Nathan Piper,  RBC - Analyst   [9]
------------------------------
 It was -- yes, I confused myself almost. I think the thing, I just want clarify drilling. So you've got foreign wells, which sounds like they're going to be appraisal wells, but you've also got to explore your portfolio to keep the government happy with the pace of progress. So I wonder if you could be realistic perhaps about what you could drill next year.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [10]
------------------------------
 Yes. I think, as we say, we've given guidance to the firm two and then multiple options. So I think the good thing about the changed environment from the point of view of contracting is that we can and will have a number of individual well options, a large number of individual well options.

 And obviously it is our intention to drill more than two wells, but that is yet to be finally firmed up with the joint venture. And work is ongoing right now actually, as I mentioned, from the point of view of the exploration prospects. And Richard's touched on a couple of them, but there are others. And it's a case that will continue to be work in progress.

 So I think from our perspective, actually having that contractual flexibility is exactly what we need. So that will probably be a rolling update, if you like, from us to the market.

 Michael?

------------------------------
 Michael Alsford,  Citigroup - Analyst   [11]
------------------------------
 Good morning. It's Michael Alsford from Citi. I've just got a couple of questions as well if I could.

 So firstly, on the Conoco (inaudible) or sale, I think, overall, the valuation was pretty disappointing to what the market was expecting. And I know you can't specifically comment obviously on Conoco, but I think what was more surprising was that industry interest was low, in that despite the low price there wasn't actually other partners -- or other players, sorry, that were prepared to pay up and get into the license given certainly the outline of the development economics that you suggest.

 So in that context, could you maybe talk a bit about what Cairn plans from a [format] perspective and a monetization perspective? Clearly you've got, what, some $300 or so million of capitalized cost in Senegal. At what point do you look to try and I guess sell down and bring in other partners to help fund the full development?

 And then just a quick follow-up on the development planning. How many wells, total, does that development plan assume? I guess I'm trying to get an understanding of the expected recovery per well that you assume in your guidance. Thank you.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [12]
------------------------------
 Yes. Okay, so let me cover the first part of that question and maybe Paul can come on the second part. I think -- don't assume that there isn't a lot of industry interest in this field. There aren't very many $0.5-billion-barrel fields out there at the minute in terms of new plays with more upside potential around it.

 And there were particular circumstances, as you know, in respect of Conoco effectively exiting a number of deep-water positions. So arguably, in the current oil price environment that doesn't give you the best environment for achieving the best price. That's their call, not ours.

 But I think from our perspective, it doesn't diminish industry enthusiasm. And I think our job, as we've said before, is to continue to ensure that we have sufficient financial flexibility -- and indeed we talked about the rig contract, rig flexibility -- to ensure that we can continue for as long as we think is appropriate before we think it's the right time to divest equity. And certainly at the minute we're under no pressure to do that. It remains an option. As I say, there is industry interest.

 And of course, if you're staying in an asset and things like carries and deferred payments become involved, you can quite often get to a very different structure in terms of absolute consideration, if you like. So we're comfortable with that at the minute.

 But, Paul, on the second point?

------------------------------
 Paul Mayland,  Cairn Energy PLC - COO   [13]
------------------------------
 Yes. I think obviously you can back out from James' numbers what the total development CapEx is. And as you said, we -- a lot of it is back-ended, i.e. we'll drill quite a number of wells through production. And we guided between 15 and 20 on initial field startup, which when we compare, for example, with Jubilee, Jubilee started up with about 17 wells. Baobab, which is a much smaller field, about half the resource space, started up with about 12. That's probably what we're starting with, for example, on Catcher and Kraken.

 So it will be a multiyear program, and ultimately the number of wells that are drilled is ultimately going to be really what is the resource base you're exploiting. But I expect it to be done in phases in a similar way to Jubilee.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [14]
------------------------------
 Mark?

------------------------------
 Mark Wilson,  Jefferies - Analyst   [15]
------------------------------
 Yes. I'd just like to -- it's Mark Wilson, Jefferies. I'd just like to just check on some of the resource upgrades. It looks like at the low end, at the 1C, the upgrade has come from the STOIIP increasing 44% to $1.8 billion. The upper end, the increase has come from increased recovery rather than a STOIIP increase, slide 18.

 I was just wondering if there is a possibility or a scenario in your appraisal results where you would see the 22% recovery factor moving down to be applicable to the lower end STOIIP, i.e. improved recovery for lower in-place numbers. Is that a scenario you could see from appraisal?

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [16]
------------------------------
 Richard, Paul?

------------------------------
 Paul Mayland,  Cairn Energy PLC - COO   [17]
------------------------------
 Before Richard's comments, I wish life was that easy actually, Mark.

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [18]
------------------------------
 Yes. I think we're at an early stage yet, which is why there is such a range. And pretty much any scenario could happen through appraisal. That's why we need to drill the wells to find out. The biggest prize is going to be confirming really how much we can recover from the upper reservoirs because that is the bigger part of the gross volume there.

 But there are still quite significant shifts that could happen in the lower reservoirs too. And that is -- as Paul I think pointed out in some of the possibilities of drilling plans, that is still something that we have to consider as well. So both is possible.

------------------------------
 Mark Wilson,  Jefferies - Analyst   [19]
------------------------------
 Okay. And if I may have one follow-up. I just wondered, there's a very large gas resort that hasn't really been talked about, and what -- how much of the developments now you show here takes that into account?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [20]
------------------------------
 Essentially, the -- we'll be reinjecting the gas to help with the recoveries in the early part of the field life. But clearly, ultimately, we will have to look at the gas resource. But at the moment that is something for later in the plan.

------------------------------
 Stephane Foucaud,  First Energy - Analyst   [21]
------------------------------
 Stephane Foucaud from First Energy. Back on the resources, I was trying to understand the contribution of the lower sand or the higher sand within the resource range. Is the 1C, for instance, mostly the lower sands and the variation therefore as we go up along the 2C, 3C, then more and more upper sands?

 Second question is around how you -- the 2C assumption compare perhaps with the view of the partner. Is it a question of recovery factor? Is it something else? I get -- Woodside as a higher figure for the 2C.

 And lastly, perhaps more on an RBL question and headroom. As we get closer to Kraken first oil and more cost is being sunk, the value of the reserve goes up. So should we expect the potential size of the RBL to go up as we reach first oil? Thank you.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [22]
------------------------------
 Do you want to tackle the RBL first?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [23]
------------------------------
 Sure. I can deal with the last question first. The guide, that $260m availability guidance between now and the end of 2017 takes into account what you've said. So effectively, the availability under the facility is driven by two things. One is an NPV calculation of the underlying fields and the other is the progress of CapEx, effectively. That capital investment is co-funded by our equity and bank debt, so as investment continues in the field, the debt capacity effectively increases, and then again when it's on-stream.

 So that $260 million takes us through to Kraken being on-stream and completed.

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [24]
------------------------------
 In terms of the split between the lower reservoir and upper reservoirs, I think the 1C, 2C levels, then the change at the lower reservoirs is relatively modest. But there is still quite a significant upside that could be realized from those through potential of further appraisal drilling, which would then allow us to remap those lower reservoirs.

 But the biggest changes are really what is going to be the recovery from the upper reservoirs. That is the focus of what we need to find out from the interference testing and further appraisal. And we assume that that is where most of the variation can come between different assessments. It's where the most uncertainty lies. And in fact if you just apply a very small percentage change in average recovery to that very large STOIIP figure you can see how it's easy to come up with slightly different figures.

 At this stage in the evaluation, we're very comfortable with where we are. But you can see it's well within the range to put quite different figures into that.

------------------------------
 Stephane Foucaud,  First Energy - Analyst   [25]
------------------------------
 And is the 1C --does it include much of the upper sands?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [26]
------------------------------
 It includes some as well, yes.

------------------------------
 Stephane Foucaud,  First Energy - Analyst   [27]
------------------------------
 And in term of comparison with the partners for the 2C?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [28]
------------------------------
 I think -- sorry, different partners could take different average recovery factors over this figure and you could still -- you can easily get different numbers.

------------------------------
 Stephane Foucaud,  First Energy - Analyst   [29]
------------------------------
 Recovery factor.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [30]
------------------------------
 Question at the back.

------------------------------
 Russell Camms,  Standard Chartered - Analyst   [31]
------------------------------
 Good morning. [Russell Camms], Standard Chartered. Can you share some details on the FPSO plans for Senegal? It might be a little early, but in terms of estimated conversion timing and costs, et cetera.

------------------------------
 Paul Mayland,  Cairn Energy PLC - COO   [32]
------------------------------
 Yes. Obviously we've got quite good experience, obviously, because we're in two projects just now, one being obviously a new-build hull and the other being a conversion. It's probably too early to state -- to say. Obviously what we're really focused on is locking down the concept and also the scale of the development. And really that's what we'll be focused on over the next 18 months or so, both through Impala with their ongoing appraisal drilling, and then I think we'll have a better assessment of it. But I don't think it will materially change from the timelines that we've had on our existing projects.

------------------------------
 Robin Haworth,  Stifel - Analyst   [33]
------------------------------
 Morning. It's Robin Haworth from Stifel. At the moment this feels like a one-hub development. I was just wondering if that's how you see it, given the exploration potential you've got a look at, and what could change your view on that. Thanks.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [34]
------------------------------
 Yes, Paul?

------------------------------
 Paul Mayland,  Cairn Energy PLC - COO   [35]
------------------------------
 Yes. I mean I guess -- and that's why we're keen to go back to do further appraisal, because obviously you're right; it is a hub. There's a large resource here. Clearly we want to move it forward and start production, but what is the scale of a facility that we should ultimately build, bearing in mind this further exploration potential? And particularly because that exploration potential sits within an easy tieback -- a relatively easy tieback range for an FPSO solution, for example.

 I don't have any further answers other than that, but it's very much part of our plans.

------------------------------
 David Round,  BMO Capital Markets - Analyst   [36]
------------------------------
 Hi. It's David Round from BMO. Can I come back to the Woodside deal metrics? I take your point about other interests and potentially being a willing seller. Is it fair to say though that those deal metrics now put a cap or a ceiling on pricing for the near future? And I guess what milestones do you need to achieve in order to see a step-up in pricing?

 And then just change the focus onto Kraken. It looks like you've got a willing seller in one of your partners there. Would you be interested in increasing your stake on Kraken?

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [37]
------------------------------
 I think on the first part of the question, there were specific circumstances for that transaction, the way it was structured. So I can't comment any more than that. I think does it cap upside? Well, that's linked to interest in the project, oil price, costs and all the rest of it. I think that's a moving picture.

 So we haven't seen any diminution in the incoming interest in this project. Our job is to ensure, as I said earlier, that if we do want to transact it's at a right time and obviously at a price that we consider attractive. So we want to keep that flexibility open.

 In terms of Kraken, as you know, we took our portion of share of partner interest early in the year with the first sole interest. I think we're comfortable with the level of exposure that we have. We do continue to look from a new venture perspective, both on the E&A side of the portfolio and also on the production side of the portfolio. So I think for us it's a balance of risk exposure to particular projects, and it may well be that we might bring in cash flow from elsewhere if we saw the right kind of deal. But we're comfortable with the level of equity we have.

------------------------------
 David Mirzai,  Deutsche Bank - Analyst   [38]
------------------------------
 Morning. Thanks. David from Deutsche Bank. A couple of different questions for you this time, firstly on Vedanta. How do you view the proposed merger between Vedanta and Cairn India?

 And secondly, I suppose on the cost base. Now, I can see you've done a lot of work on the CapEx to bring it down to $12 to $15 a barrel. If I can split that into drilling, completion and subsea, what kind of scope do you see for further reductions there? And the OpEx number was fairly nailed on at under $10 barrel. Do I not understand that there should be significant scope going forward to bring the yard costs down for FPSOs and could you not actually make savings there or do you not expect to see the yards bring down their cost expense?

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [39]
------------------------------
 I guess on the -- I'll hand over for the second part of your question. On the first part of the question, we -- as you know, we haven't made any public comment on the proposed Vedanta transaction. There's a shareholder vote I think on September 12 and we'll vote accordingly, so I guess you'll find out then how we view it.

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [40]
------------------------------
 On the CapEx and OpEx estimates for Senegal, I guess we're in the middle of contracting a rig at the moment and we're in the middle of seeing what the contractual relationship is like with two FPSO constructors at the moment. I'd say in the guidance we gave today we probably haven't taken the most aggressive end of the range that you see in today's environment because we've tried to predict what it's going to be like over five years or more, getting us through to first oil. And the CapEx numbers there, well, the economic outputs there include a 20% contingency.

 So of course, if the oil price stays where it is today or goes lower, then there's the potential to see some of the possibly more aggressive contracting strategies that are existing literally as of today. But we've tried to predict something that's perhaps more sustainable.

 And then on OpEx, again, I think it compares reasonably well with analogues. I think Jubilee OpEx is probably $8 a barrel, something like that. It is of course linked to your oil price outlook.

------------------------------
 David Mirzai,  Deutsche Bank - Analyst   [41]
------------------------------
 Jubilee, they own their [site]?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [42]
------------------------------
 They've gone through the purchase option now, yes. Yes.

------------------------------
 David Mirzai,  Deutsche Bank - Analyst   [43]
------------------------------
 And now it's [$8] a barrel? So your $10 a barrel is inclusive of leasing costs or --?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [44]
------------------------------
 It includes leasing costs, yes. Sub $10 is roughly half and half. So if you work that out on a -- as you saw on the chart there, 100,000-barrel-a-day, roughly 100,000 to 130,000-barrel-a-day production, peak production rate, you can back out from that what we're assuming to be the day rate on the FPSO.

------------------------------
 Anish Kapadia,  Tudor Pickering Holt - Analyst   [45]
------------------------------
 Hi. It's Anish Kapadia from Tudor Pickering Holt. I had a few different questions. First one on India. Could you just give a bit more detail around the process? And the way I understood it is that you're going to have the hearing in the first half of next year, so should we have a definitive resolution at some point next year?

 Second question was on potential hedging strategy with the new fields coming on-stream. What's the thinking around that?

 And then final question on Skarfjell. Just wondering, you've got a concept selection coming up at the end of this year. Is there any CapEx allocated to Skarfjell for 2017? And is that an asset you want to continue in? Thank you.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [46]
------------------------------
 Yes, as to the very final bit of the question. But, James, I'll let you --

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [47]
------------------------------
 Yes, sure. Well, just to continue on the last one first, on Skarfjell, in terms of projections, there is I guess continued pre-development type spend and studies included in our CapEx projections for Skarfjell. But clearly we won't be giving a detailed development CapEx scenario until it reaches FID post-concept select.

 On the other two points, you're right; that is the timetable for the arbitration process that's been set out. Clearly we don't include, in terms of our funding plans, a firm resolution of $1 billion inflow in terms of the compensation we're seeking from the arbitration panel in 2017 because there is risk to that schedule. And clearly if you look at international arbitration processes around the world, they do tend to get delayed rather than be accelerated.

 So we take a cautious on that, but actually we've been encouraged by the approach that the panel members have taken so far in terms of trying to keep this on a tight timetable.

 And I think the second question was around hedging strategy. Our strategy on hedging is not to do it for its own right in terms of protecting against oil price volatility, but to do it to protect debt capacity and CapEx programs. And we'll continue to look opportunistically to do that. As of today, it probably isn't the best time to be trying to tie in a floor, but between now and first oil we'll continue to look at that.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [48]
------------------------------
 Okay.

------------------------------
 Caren Crowley,  Davy Research - Analyst   [49]
------------------------------
 Good morning. Caren Crowley from Davy. You mentioned in your results that the amount of capital available under the debt facility is $260 million, and I assume you derived that from the outcome of the redetermination talks you had in March with the banks involved in the RBL. Can you say what sort of oil price or the forward curve they were assuming when you calculated the $260 million as capital available under that facility?

 And coming into September, I assume there's another redetermination process, and whether you think that'll be more favorable in terms of increasing the capital availability under the facility or whether it could limit it and reduce that figure of $260 million? Thank you.

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [50]
------------------------------
 Yes, sure. So that's right; the $260 million guidance is based on the re-determining process and the model that was agreed back in March. That's phased availability obviously as investment in the two fields continues between now and the end of 2017.

 And in terms of whether that guidance remains current or not, the re-determination process back in March was, the next three years, say roughly around where the forward curve is today, stepping up towards a long-term oil price view of in the high $50s.

 The oil price has continued to be relatively volatile and different banks take different views. We've actually seen a slight improvement, if anything, in terms of bank price decks. So if we're running the model today with the updated price decks that guidance might be a bit higher. But clearly we won't update it formally until the September redetermination, but I'd say it remains pretty current.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [51]
------------------------------
 The last, Mark?

------------------------------
 Mark Wilson,  Jefferies - Analyst   [52]
------------------------------
 Just one follow-up question from me. Regards the OpEx and the question of leased versus new-build FPSO, it seems pretty much the mantra that people go for leased FPSOs these days and reduces your cost to first oil. But given the large in-place volumes and therefore, arguably, a very long life of this field if you can work out how to recover it all, is there a scenario in the concept select, and given the way costs are going as well for new builds, for an owned FPSO development concept?

------------------------------
 Paul Mayland,  Cairn Energy PLC - COO   [53]
------------------------------
 I guess, James, it's fair to say it'll be under consideration. There's no doubt about it.

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [54]
------------------------------
 Yes. And obviously there's -- what would be standard is also the option for a purchase after where you can negotiate the number of years, and today you'd be in a reasonably strong negotiating position. Clearly that needs to tie in with financing plans for a development scenario and how much therefore of an equity check you're having to put in up front and how that ties in with a cost-recovery profile and so on. So -- but clearly it'll just be a question of running the economics.

------------------------------
 Simon Thomson,  Cairn Energy PLC - CEO   [55]
------------------------------
 Okay, so it's a little bit after 10 o'clock. I think we'll call it a day, but thanks very much for your attendance. Thank you.




------------------------------
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