Full Year 2015 Cairn Energy PLC Earnings Call

Mar 15, 2016 AM EDT
CNE.L - Cairn Energy PLC
Full Year 2015 Cairn Energy PLC Earnings Call
Mar 15, 2016 / 09:00AM GMT 

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Corporate Participants
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   *  Simon Thomson
      Cairn Energy PLC - Chief Executive
   *  James Smith
      Cairn Energy PLC - CFO
   *  Richard Heaton
      Cairn Energy PLC - Exploration Director

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Conference Call Participants
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   *  Aaditya Chintalapati
      Pareto Research - Analyst
   *  Alex Topouzoglou
      Exane BNP Paribas - Analyst
   *  Nathan Piper
      RBC Capital Markets - Analyst
   *  James Hosie
      Barclays - Analyst
   *  James Thompson
      JPMorgan - Analyst
   *  Kate Sloan
      Macquarie - Analyst
   *  Thomas Martin
      Numis - Analyst
   *  Tom Robinson
      Deutsche Bank - Analyst
   *  Daniel Ekstein
      UBS - Analyst
   *  Mark Wilson
      Jefferies - Analyst

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

 As in the usual way, we've got a presentation to run through with you this morning. And we'd be happy to take questions at the end. And it's being webcast, so there will be microphones. If you want to ask a question, please state your name before doing so. (Conference Instructions)

 So, turning to the first slide of the presentation, Cairn's strategy is straightforward. Our balanced E&P portfolio provides, on the one hand, exposure to full lifecycle, mature basin position in the North Sea. And on the other, Cairn operated exploration in emerging and frontier basins.

 The consistently disciplined approach that we have to capital allocation means that the model is sustainable and well positioned to deliver further growth for shareholders. And I would emphasize that we remain fully funded in respect of all of our commitments, with flexibility on top of that.

 As you all know from the operators, our core North Sea developments, Kraken and Catcher, are substantially under budget and on schedule to deliver first oil next year. Combined production costs on plateau of well below $20 a barrel -- James will come on to -- means that each of those projects are attractive sources of future cash flow for Cairn in the current oil price environment.

 And we're very pleased to have secured an additional 4.5% of Kraken in what was a value-accretive transaction for Cairn. And, importantly, the associated CapEx, in relation to that 4.5% interest, has already been, effectively, covered under the general reduction and project costs we see across the whole of the Kraken project; again James will come on and talk a little bit about that.

 Senegal remains a very significant and exciting part of the portfolio that continues to demonstrate growth and further growth potential. As you will have seen from today's announcement, following the results of the discovery well and the first appraiser well, SNE-2, we've upgraded our 1C condition resource numbers by 30% to approximately 200m barrels. And, as you know, from our Capital Markets Day last year, that was the main purpose of that well. It was about proving up the 1C.

 So we're very pleased with that; we're very pleased with what we see as a significant increase. And we look forward to coming back to you with further revisions, once we've had the opportunity to go through what was a very successful result on the SNE-3 well, the most recent appraisal well that we announced just last week or the week before. So, a continuing story of revisions.

 We're now currently on the Bellatrix 1 location which, as you know, is combined exploration and appraisal well. And we look forward to coming back to you with the results of that well in due course.

 Operations are progressing extremely well. We are substantially under budget in terms of the program. And we're approximately one month ahead of schedule.

 And I think it's important to reflect on the fact that the three-year extension that we received at the beginning of the year from the government of Senegal, allows the joint venture sufficient time to properly appraise the SNE discovery, and also to follow up on further exploration on the block.

 We've got a huge amount of data that Richard will come on and talk about, in terms of everything that we've collected on these wells, the 3D seismic that we're working through. So it does give us time to properly plan, to get the right development going forward for SNE, and also to prove up that exploration on the block. We believe we're already substantially down the path of proving up the 1b barrel block-wide number that we talked about at the Capital Markets Day.

 If we move on to the next slide, Cairn's strategy of providing exploration-led growth from a fully-funded, balanced portfolio, as you know, has been consistently delivered over a number of years now. And central to the ability to deliver that strategy, is creation, addition and realization of value across the portfolio.

 Accordingly, when we look at our emerging and frontier-basin positions, we are always seeking to access large acreage interests that offer the potential for follow on in the event of success, but also, absolutely fundamentally, are not only technically but commercially attractive in the current oil price environment.

 And our track record of returning over $4.5b to shareholders within the last 10 years, I think, clearly demonstrates a consistent focus on roots to monetization and potential further returns.

 We believe, as a Company, we are well positioned to benefit from the current lower cost environment in the oil price downturn. We see clear evidence of that in the North Sea developments, as I've just talked about. We've also seen evidence of that in the attractive rates that we've been able to secure in Senegal, not only for the rig but for 3D seismic and services. And we see the potential to access further attractive rates as we look to future operations in Senegal and, indeed, elsewhere.

 In addition, combination of industry distress and strategic withdrawals means that there are opportunities to add to the portfolio. But I would emphasize that, although we constantly screen opportunities, we would only ever act where we see something that is value enhancing, a clear strategic fit, and does not materially diminish the financial flexibility that we're so focused on.

 So, in the meantime, we're focused on adding value from within the current portfolio and maintaining that financial flexibility. And on that point, I'll hand over to James.

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 James Smith,  Cairn Energy PLC - CFO   [2]
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 Thanks, Simon, and good morning, everyone. So in the next few slides I'll take you through the 2015 cash flows and then on to the current funding position and the forward capital program, with an update on the two key development projects.

 I guess, before I do that, as an overarching remark, the strategy, as you'd expect, has really been about reducing the cost base, about reshaping and reducing the capital program going forward, and about retaining balance sheet strength. These are all things you'd expect me to say, but the reason we're doing them, is so that wherever we're investing in the portfolio, it's in assets that generate returns in the lower oil price environment, and in a continued lower oil price environment, and it's in order to position the Company so that, not only we can withstand a continued lower oil price environment, but that we're able to take advantage of it.

 So looking first at the 2015 cash flows, you can see the opening cash position of $869m there. The total spend on Senegal during the year, on an exploration/appraisal activity, was $114m. That's the conclusion of the exploration program and the beginning of the current appraisal program. $106m in the UK/Norway region represents exploration/appraisal activity and pre-award costs; that's licensing activity in Norway. A significant component of that is in Norway and we'll benefit from the Norwegian tax rebate in later periods.

 $24m of other there relates predominantly to Morocco and the Cap Boujdour well earlier in 2015.

 $114m of development CapEx is all on Kraken. We were fully carried on Catcher during the year, following completion of our farm-out to Dyas. And on that, the farm-out proceeds during the year, at closing of that farm-down of Catcher, were $55m, in January when that transaction closed.

 And then the other cash inflow item during the year is the Norwegian tax rebate of $52m, which, with the balancing item there, abandoning costs, financial expense and income and FX adjustments, takes us to a year-end cash position of $603m.

 Moving on to the Group funding position, and, if you like, the existing sources of capital and uses of capital that we've committed to, the $603m available in cash there at the beginning of the year, as I've mentioned, there is a Norwegian tax receivable during the year of $33m.

 And then the other key source of capital is clearly the RBL facility, reserve base lending bank facility that we put in place to fund Capture and Kraken in the North Sea. That remains undrawn. The headline facility size is $570m. As you know, availability under that facility is driven by evaluation and NPV determination by the banks, carried out every six months. And drawings under that facility will be shaped to the CapEx program of the Capture and Kraken fields.

 So we currently expect the peak availability under the facility will reach about $335m, but during 2016 and 2017, or by the end of 2017 drawings will reach about $260m over this key funding period that we're looking at.

 And the other item there is obviously operating cash flows in 2017, once the fields are on-stream. Clearly, that will depend on oil prices at the time. But, given the low production costs on these two fields, which I'll come on to, operating cash flow will be significant even at the forward curve.

 So in looking at the current uses of capital, it's a relatively straightforward story actually. $465m committed to the UK developments over 2016 and 2017, and I'll come down to a bit of a breakdown of that on the next slide; $135m of committed exploration/appraisal activity predominantly in Senegal relating to the current three-well program.

 And then, what we call on this slide, discretionary E&A and other things, that clearly predominantly relates to the anticipation that we will be continuing to actively invest in Senegal. That full program isn't precisely defined in terms of costs yet, but clearly we've talked about at least a six-well program for this three-year evaluation period.

 So, simplistically, I guess, on this slide, you can see that the existing sources of capital, without any operating cash flow, total about $900m. And the committed uses of capital, so that's the two development projects and the three wells in Senegal and other exploration, totaled about $600m. So you can see, we've got significant flexibility to continue to invest in the portfolio and to continue to grow the portfolio.

 I guess a final point on this slide is none of these funding plans rely on monetization of our remaining assets in India. Clearly, over time, we expect there will be a cash inflow from a positive resolution of that legal dispute that's going on in India, but we don't rely on it for funding plans.

 The international arbitration process on the Indian dispute has begun. The arbitration panel has been appointed and the Indian government is fully engaged in that process, as they're required to be under the UK/India treaty. We expect that preliminary hearings will occur fairly shortly and the process will continue from then.

 In-country, we continue the work in progress, if you like, with the tax office, that's to appeal against the assessment that we've received. And we continue to engage, very positively, with the politicians in India. But I think the base case is probably that this will be resolved through the international arbitration process.

 Important point, final point to make on that, is that the -- in the downside, the liability to us, if you like, is ring-fenced to our assets in India. So the only assets of the subsidiary that's seeking to be taxed are effectively the assets in India which have already been attached.

 As I said, a bit more of a breakdown on that capital program. On the left-hand side there you've got the committed E&A program, $135m. You can see that's predominantly in Senegal; that $100m of remaining CapEx from January 1 this year onwards relates to the continuing three-well program, $25m in the UK, and Norway region relates to early-stage exploration activity. And in the UK this year we'll be drilling the Laverda exploration well in the Catcher region. And there's $10m for activity on the rest of the portfolio.

 On the right-hand side you can see there the split between Catcher and Kraken for that total $465m. The important point to make here is $465m represents a significant reduction on our previous guidance for the development projects. At the beginning of the year we were guiding around about $500m across the two projects in 2016 and 2017. And that was before we had acquired the additional 4.5% stake in Kraken. So that took us up -- that would have, on a pro forma basis, taken us up to something like $550m. So you can see this revised guidance represents at least a $90m reduction in development CapEx net to Cairn.

 Finally on this, you can see there's a split of -- the phasing of that CapEx is roughly evenly split between 2016 and 2017.

 So on the development projects, starting with Kraken, the project remains on track for first oil in the first half of next year, following which it will ramp up to gross production of 50,000 barrels a day. As you see, we have 29.5% of that. Progress is going well. The drilling is ahead of schedule and all the results, the injectivity results have indicated reservoir properties at or above expectations.

 Subsea installation continues on track and is well progressed for completion later this year, in readiness for the FPSO arriving. As I think we've said previously, the operator has said it's really the FPSO that's critical path to first oil on this project. And progress there is also strong. The whole conversion is nearly complete and integration will begin later this year.

 As I've mentioned, we've seen significant cost savings on the forward capital program on Kraken; $300m of gross CapEx savings across the project have already been announced by the operator. That represents about 10% down on the sanction case. And I would say that, in the partnership, we're actively working on ways to further reduce that and to optimize the capital schedule.

 Moving on to Catcher, it's a similar story in many ways; first oil later in 2017 again ramping up to around about 50,000 barrels a day gross. We have 20% of that. Again, development drilling is ongoing. Flow tests and reservoir results there have again been encouraging. And subsea installation is progressing well.

 As previously announced, there were some constraints in the yard in the Far East with the FPSO hull construction. But the mitigation plan for that is now in place, with the first section having been delivered. And we're back on track for first-oil delivery in 2017.

 Again, on the cost side, it's a positive story. The project was materially under budget during 2015. And clearly the partnership is very focused on making sure that that trend continues.

 So just to summarize on the key messages, I guess, about positioning the Company for a lower oil price environment, we've significantly reduced G&A. That's down around about 50% or 40% on a like-for-like basis to $30m admin expense, you'll see in the P&L. On a recurring-cash basis, that represents about $11m of cash cost running the business.

 It's been a core strategic objective of us, throughout the history of the Company, to make sure that we have flexibility in the portfolio so that we can constantly be flexing the capital program to make sure that we're investing where it will deliver the best returns. On the one hand, you'll see at the beginning of this year, we completed a farm-down of the Catcher asset that took out around about $380m of capital commitments from the forward program.

 On the other, opportunistically, where we see the opportunity to do so, we acquired 4.5% additional interest in Kraken for -- on what were obviously very favorable terms.

 And in terms of the E&A portfolio, we've already focused that down on Senegal. Non-core E&A activity has been either postponed or, where it simply doesn't make sense in a lower oil price environment, extinguished.

 We've talked already about the CapEx reductions across the development programs, but clearly those help with the returns on those projects, and they help with the funding position of the Company over the next couple of years pretty significantly.

 On earlier stage in the appraisals asset life point, clearly on Senegal we've been benefiting, very fully, from lower service sector costs and continue to do so.

 So, all of that means that, wherever we're investing dollars, it's in low breakeven projects. So, in terms of near-term cash flows, the cash breakeven cost, or the all-in production cost if you like, across Catcher and Kraken will average $17 a barrel in the first few years of the production. And when we look at where we're investing in full-cycle projects, principally Senegal, we see that, on a P50 case, the breakeven there will be somewhere in the $30 oil price range, which is obviously extremely robust.

 So, in summary, the focus is very much on the current portfolio; on delivering the development projects to deliver cash flow in the near term and, obviously, in terms of value growth on Senegal.

 We have the balance-sheet strength to support that investment. Beyond that, we do have some balance-sheet flexibility to continue to grow the portfolio. But I would say that any new investment decisions would have to meet the stringent economic parameters that we've put in place for considering those investments.

 And on that point I'll hand over to Richard to talk about the E&A program.

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 Richard Heaton,  Cairn Energy PLC - Exploration Director   [3]
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 Thanks James, thanks Simon. And good morning, everyone. I'm going to talk mostly this morning about Senegal; that's where most of the action is at the moment, and then finish off with summarizing our position in the North Sea.

 So, as you know, over the past few years we've been rebuilding a portfolio that's a balanced portfolio that includes frontier, emerging basins and balanced by the North Sea, a mature basin. But along the Atlantic margins, our frontier and emerging basins strategy, we've built acreage positions from Senegal to Mauritania and Morocco and drilled in all those places.

 The success has come in Senegal, chasing up where the early explorers, in the 1960s and 1970s first looked in the shallow water, found bits and pieces of oil and gas, but nothing commercial. What we have done is taken modern-day 3D seismic data and the modern-day capability of dynamically positioned drillships to get into the deepwater.

 And with our first two wells in Senegal we have two discoveries, opening up a new basin, a tremendously exciting thing to do; the nearest commercial hydrocarbons to here are hundreds and sometimes thousands of kilometers away. Within 18 months already from starting drilling, we're on our fifth well. And we've continued to build on success.

 The second of discoveries was the more attractive. It came across as a better reservoir than we had expected in SNE. We started off, before drilling, with a position here of prospects. We thought it had about a mean number of about 185m barrels recoverable. That's based on analog data around the area. When we drilled the SNE-1 well, we were very surprised to see better quality reservoir than we had anticipated. And when we re-mapped it, at that time we found that it extended over a greater area.

 And so, last year, we gave a revised guidance, now a contingent resource, which ranges from a 1C or a proven number of 150m through 2C proven and probable 330m, and 3C proven and probable and possible of 670m.

 What we've done today is given up data based on the first of the appraisal wells that we have drilled, SNE-2. This went towards what we anticipated to be the crest of the field. It's focusing on making sure that the crest really is the crest -- we had different maps available to us at the time, even after the first well -- aiming really to firm up that 1C and 2C number.

 And, indeed, the results of the well, as I will come to, have been very successful. And, in fact, we've now upgraded our resource range 1C of 200m, 3C -- 2C of 385m and a 3C of 690m. So the impact, indeed, has been at the lower end, the firmer end. And that's what you'd expect by taking what would normally be a lower-risk appraisal well into the center of the field.

 The whole program, though, is aimed not just at the field itself; we have an evaluation program over the whole of the license whereby we're looking to look at the -- both the discoveries and also the new exploration potential. But right now we're focusing on the main field, the SNE field we've discovered.

 So here was the discovery well, SNE-1. The second well went towards where we thought the crest of the field was. Indeed, it's proved that that is the crest of the field; it's proved the depth conversion there. The second well, just announced last week, went to where we thought, towards the southern edge of the field. It's not quite as far south in the field as we had imagined. In fact, the field seems to extend a bit further than that. And, right now, just recently, we have de-spudded the Bellatrix well, which includes an exploration target here, as well as having an appraisal target.

 And essentially, those -- all the wells so far have been successful. We've managed to test hydrocarbons now from SNE-2 at very high rates, particularly in the deeper, lower reservoirs here, where the first-flow tests reached 8,000 barrels a day. That's a tremendous flow rate. And most recently, last week, at the edge of the field in the upper reservoirs, which are generally not as good quality, of over 4,000; in fact peak rates of over 5,000 barrels of oil a day.

 What we've demonstrated so far is that we have a consistent field-wide gas-oil contact. We have a consistent field-wide, oil-water contact. We have predictable reservoirs. Between these three we can correlate them very well. We can see them on the seismic as well. And, essentially, it looks like we've got a building resource. And what we've -- I'm going to show you, when it comes to the resource of SNE-3, is that things continue to move in that direction. And what we find is good fields tend to get better as you evaluate them; and that's what we're hoping and that's what we're seeing here.

 To go back to SNE-1, very briefly, very successful discovery well. We had a dual target here actually, both in the clastics here, in the Albian, and also deeper targets in the carbonate. The carbonates didn't come in; they were water wet. But the clastics came in better than we expected. And that has been continued to be worked; the data collected from that has been worked. This is showing side wall cores here that we collected in that well. We're going to examine them microscopically and -- through a scanning electron microscope, to work out exactly how the oil is going to be drained from these sorts of rocks.

 And they are quite productive rocks, and that was demonstrated at SNE-2. And here, of course, first appraisal well announced -- the results announced in January this year. Towards the crest of the field, the well tests have said we're very successful; not only did the good lower reservoirs come in at 8,000 barrels a day on test, but a very small interval in one of the upper reservoirs also came in 1,000 barrels a day, confirming the potential for productivity here, something that we've been recently been confirming with the third well.

 Not only that, but we cored the whole of the reservoir, right through the gas column, through the oil column and into the underlying water column, three cores; 100% recovery. Very rare to get that. It demonstrates that the rock is indeed quite easy to drill.

 We've got a huge amount of core logs -- of logs of new seismic over the area as well from the appraisal program, which again confirm the depth conversion that showed the shape of the field and, effectively, demonstrates an increasing resource that we've just announced.

 The third well, announced just last week, this is about three kilometers south of the discovery well, SNE-1. So SNE-3 here to the south, about three kilometers; SNE-2 about two kilometers, two and half kilometers to the north of SNE-1. So this is getting to be a large area.

 Here the idea in the well was to try and encounter these uppermost reservoirs that we saw in the wells, SNE-1 and 2, to get those entirely within the oil columns -- so we're heading towards the southern part of the field -- and to test how these upper reservoirs here, that we saw, how would they produce once they got into the oil lake, because, volumetrically, they're quite significant for the field.

 And we thought we'd chosen a location where we'd encounter them within oil; they came in half within oil, half within gas. That means the field is bigger than we had mapped it before. So we're looking now to do that re-mapping. And we'll be incorporating the huge amount of data that we've acquired so far, together with the new well results, the ones that we're drilling right now, before we give a further update.

 What this well has shown is, producing tests from within these upper reservoirs, peak rates of over 5,000 barrels a day, and also stabilized rates in the 4,000 barrels a day over a quite long period of time. We did notice a little bit of pressure decline in here after the test, and that indicates that these sands are not perfectly connected. And that's what we expected; that's what we need to understand yet in the remainder of the evaluation program, where we'll need to conduct interference tests to understand just how many wells will we need to drill and drain in the development of these upper reservoirs.

 But again, here, we've collected an entire core, right through the oil lake here, 100% recovery again, a huge amount of log data, a huge amount of test data. And what we're doing now, and what we'll have to do next, is to incorporate that into the next part of the field evaluation. So things are getting bigger, things are getting better and that's what we aim to continue to do.

 Right now we've moved on to the Bellatrix well. The primary target here has always been seen as the exploration target here. We saw this before we drilled even the first well in the license and it was a possible place that we could have considered for the first exploration well in fact. What we now know is it does overlie towards the northern end of the SNE field as well.

 So it's a dual-target well, first of all, into these reservoirs here. And there are seismic anomalies here that make it difficult for this not to be oil or gas; we're not quite sure of the proportion yet. That's the fun in exploration, but essentially, whatever it is, it will be able to be developed because it's so close to SNE. It overlies it. It will add to the resource base if it comes true. It's quite a large prospect, but we'll see what the results are when we get those out. That should conclude some time towards the end of this month, early into April. It's drilling right now.

 Of course, it's very unlikely that, with the first two wells -- here's FAN-1 it fanned a 500m column of oil here; much poorer reservoirs in the deeper water. Second success here now proven to be a appraisal success here in SNE. It's unlikely that this is the only oil and gas in the block. We have always seen an array of prospects and leads here, right from the time that we farmed into the license. And essentially, we have more new seismic data now that we've just acquired as part of this evaluation plan, over the eastern part of the license, and we've taken a swathe of this new seismic data, it's high resolution, more than 3D. And we should be able to update that.

 What we say for the whole block here is a mean resource assessment for the block of around about 1b barrels -- if what we're seeing in the field and the prospects and the leads is all added up at the end of the day, a mean risk number of about 1b barrels. It's a very crude estimate; obviously, as we integrate all the data, that could change. And it's looking very positive at the moment.

 What we do aim to do, within the three years we have to evaluate the whole of the license, is to make sure that the best of the exploration prospects is also drilled, and that's within the evaluation plan.

 We're evaluating not just the shallow area here, where drilling is relatively straightforward and simple -- in fac,t all the wells are under time at the moment, it's proving very simple to drill -- but also potentially go back into the deeper water and evaluate those reservoirs there where they may improve, away from the FAN-1 well.

 So, the forward program in Senegal, fairly straightforward. Our vision, really, is to make sure that there is a anchor project around SNE-1. It looks like we're moving in the right direction there. There's likely to be some kind of FPSO; that's the concept in mind at the moment. Assuming production rates at somewhere in the plateau of 50,000 to 100,000 barrels of oil a day. Of course, that could be changing as things move up. But that's the current thought.

 And the next steps, obviously, are to integrate this mass of data that we have and are still continuing to collect. We will core-in Bellatrix-1 for instance, through the northern part of the SNE field. That's another huge amount of core data; lots more log data.

 We will be, potentially, moving to further wells, obviously, through the appraisal program. We must conduct an interference test somewhere in the future to make sure we understand the connectivity in these upper reservoirs in particular.

 And what we will do then is bind all that information together and, over the next few years, pull together what we see as a commerciality report, pre-feed data, aiming really for, ultimately, we think, probably, the earliest we can get to field here on production is 2021. A lot of that all to come, of course, but very exciting.

 So that finishes, really, a quick run-through of Senegal. Of course, on the other side of our balanced portfolio, we have an interest in and large portfolio in the UK and Norway.

 Of course on the other side of our balanced portfolio we have an interesting and large portfolio in the UK and Norway in a mature basin. Over the past year we've been very careful to look at that portfolio, make sure that the less attractive parts the work is deferred or areas are relinquished and focus what we believe on the interesting exploration activity which is around the fields that we already have. So James has explained a little bit the status of Catcher and Kraken; we do have exploration acreage around there which is very attractive potentially to be tied into those fields.

 And also in Norway we have the Skarfjell field which we discovered in 2012. That should be aiming towards a concept select decision later this year. We have a big exploration position around there too. What we've also been doing in Norway is applying in the latest license round. We collected another five licenses earlier this year from last year's license round and we applied in the Barents Sea, essentially an emerging basin within Norway up in the north as well last year. That result's out later this year.

 So we've picked up and building a portfolio here; we're making sure it's very focused though and it does look attractive to us.

 As well, of course, Norway and the UK we do have other areas that we're looking in in the North Atlantic. I'm not going to go through them in detail here. We are building our portfolio of prospects and leads there as well but we are making sure that where we are going to put our investments, obviously it's got to make a difference and it's got to actually be a value-enhancing fit with the rest of our portfolio.

 And with that I'll hand over to Simon.

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 Simon Thomson,  Cairn Energy PLC - Chief Executive   [4]
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 Thanks Richard. So in conclusion, Cairn remains fully funded with a disciplined approach to capital allocation and sufficient financial flexibility to have follow-on in further Senegal success. Balance is maintained across the portfolio with growth opportunities in both the mature basin position that Richard has just alluded to and also in our frontier and emerging acreage.

 We have a high quality and growing resource base and we have significant growth opportunities, principally in the near term in Senegal where, as you've heard, a combination of successful appraisal, strong flow test results, a material resource base, and as Richard commented, we're now more than double our pre-drill resource estimate, an additional upside, not only from analysis of the results of the SNE-3 well but also from the ongoing drilling program provide the potential for further significant upside for shareholders.

 So that concludes the presentation and with that I'd like to hand over to the floor for questions.

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Questions and Answers
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 Aaditya Chintalapati,  Pareto Research - Analyst   [1]
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 Hello, hi. Aaditya from Pareto. Thank you. Just one question really. Given that you are ahead on your current planned appraisal drilling on Senegal, could you just talk around any potential for a possible fourth well going in the current project?

 And also secondly, you've talked about strategic fit when you're looking at other acquisitions or anything of that sort. Could you just give us a little bit of color on what you think would be a good strategic fit right now? Are you looking for production or would it be more appraisal/exploration and things like that?

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 Simon Thomson,  Cairn Energy PLC - Chief Executive   [2]
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 Sure. On the first point, I'll just quickly answer. The joint venture's right in the middle of deciding that so in fact meeting this week. And as you know, the way we designed the contract it's three firm and then three individual effective options on the drilling contract. So we'll see where we get to as a joint venture. That's clearly a possibility. Whatever happens, there will be further activity in Senegal; it's just a question of timing and matching to the enormous amount of data that Richard has alluded to.

 I think on the second point, I'd emphasize that the focus is on the current portfolio. We are seeing more opportunities like any other oil and gas company and we do continually screen. I think from our perspective what we're looking at is things that don't result in material diminution to that financial flexibility. So if for example there was a production opportunity, it would need to not be burdened by historic abandonment or infrastructure costs and so on; it would need to be capable of being accretive in the current oil price environment. And that limits the amount of opportunities that you naturally can look at. We don't need it, so again if there was something it would have to stand out for us.

 I think on E&A, up until recently we've seen that there hasn't really been very much coming through that's been attractive from our perspective. I think what we're seeing now, especially with, as you've seen, strategic withdrawals by majors from certain regions or planned withdrawals, there are certain more attractive opportunities coming up that again fit our profile of having to be commercially as well as technically attractive and survive screening in the current environment.

 So it's a bit of a long-winded answer to say that there is nothing specific and if there is something, the main focus for us it not to reduce our financial flexibility and to actually add to the strategic fit, that balance that the portfolio currently offers.

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 Alex Topouzoglou,  Exane BNP Paribas - Analyst   [3]
------------------------------
 Hi there. Alex Topouzoglou from Exane. Could you -- three questions please. Could you please provide a more detailed timeline on the India arbitration please?

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [4]
------------------------------
 Yes, James?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [5]
------------------------------
 There is not a preset fixed timeline for the arbitration process. The steps are effectively that there will be some preliminary hearings which we expect very shortly which will set out some procedural matters like the seat of the arbitration and the timetable for if you like the main claim hearings. Then we will submit shortly after that our full statement of claim, which effectively we've set out the case pretty extensively when we initiated the arbitration process but there's a formal claim document with expert witness statements and all that kind of thing that goes in in the coming months. And then India is invited to respond to that and then the arbitration panel of three will deliberate and possibly cross-examine and determine after that.

 Now that whole process is unlikely to be less than 12 months and you will find examples of arbitrations clearly that have run on for longer than that. It's difficult to give more precise guidance than that.

------------------------------
 Alex Topouzoglou,  Exane BNP Paribas - Analyst   [6]
------------------------------
 Okay, thanks. On that point mentioned earlier about new opportunities, acquisitions and so on, looking at home, what you've got in Senegal, could we expect some of that capital to be allocated to testing new prospects in the next 12 to 18 months?

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [7]
------------------------------
 Yes.

------------------------------
 Alex Topouzoglou,  Exane BNP Paribas - Analyst   [8]
------------------------------
 Okay. And then with that, would you sell down Senegal ahead of that campaign or would you take it with your current equity position?

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [9]
------------------------------
 I think that's a good question and I think we've been pretty clear that for us it's about maintaining our equity position until such point as we see it's the right time to monetize all or part. And that has been our track record in the past. I think partly that's opportunistic so there's not a timeline attached to it. This is a very attractive asset; we want to ensure that we've fully proved up as much value as we see before or at least any offer that we might be considering reflects that value properly so that we're acting in the best interests of shareholders. So it is always in our minds but it's something that we want to ensure we have flexibility to continue going with the program until the right time, which could be next year, could be the year after, could be whenever an opportunistically attractive offer comes.

------------------------------
 Alex Topouzoglou,  Exane BNP Paribas - Analyst   [10]
------------------------------
 Great. And then finally, on page 14 of the release you mention that delays would have an impact on the liquidity position and so therefore -- but you're still able to conclude the going-concern assumption. So I'm just wondering, obviously you could monetize some of your assets, you could sell -- there's a whole number of things you could do, but how long a delay on both projects would the balance sheet be able to absorb in your view?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [11]
------------------------------
 Well, what I would say is that the RBL facility, so the debt facility, is based on running effectively stress scenarios both in terms of quantifying the debt available but also in making sure that the business continues to be fully funded to deliver cash flows. And so that considers at least six or more months' delays on both of the projects and the balance sheet is certainly robust for that.

 Now beyond that, I think as you've seen on the slides we've shown, there's reasonably considerable headroom, funding headroom over the next couple of years. It would depend somewhat on the shape of the two projects running together. Clearly, Kraken is anticipated to be on stream first and operating cash flows from that will fund Catcher development as that goes on. So actually they fit rather neatly together.

------------------------------
 Alex Topouzoglou,  Exane BNP Paribas - Analyst   [12]
------------------------------
 Okay, great. Thank you.

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [13]
------------------------------
 Next at the front here.

------------------------------
 Nathan Piper,  RBC Capital Markets - Analyst   [14]
------------------------------
 Thank you. Two questions from me. First of all on the drilling, I know (inaudible). So looking at SNE-3 first of all and then the SNE-4, the deepening of Bellatrix, can you comment on whether each or both of the wells are inside the 2C and 3C existing resource cases or outside them i.e. outside the contours that currently define those two numbers?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [15]
------------------------------
 No, they're both within the area of the overall field. Essentially we're looking at a core area. Obviously as you get towards the edges of the field it becomes increasingly thin but these are still well within the core area of the field. So it's a question of just where the rest of the field is around the outsides of those.

 Of course we haven't yet drilled Bellatrix so that remains to be seen. You could argue that SNE-3 was a relatively long step-out well really towards the southern edge but it turned out not to be. We may not have found sands there that were a decent quality but indeed we have. It still remains obviously an object of the appraisal to ensure and confirm that the Bellatrix well is also well within the field at that point. That's what we expect but we still have to drill it.

------------------------------
 Nathan Piper,  RBC Capital Markets - Analyst   [16]
------------------------------
 So you avoided being specific at all there so I'll try again. Are you drilling these wells beyond the 2C number? So are you drilling -- so was SNE-3 beyond the 370 you spoke about today?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [17]
------------------------------
 Well, the way we've arrived at the 2C number, it's a stochastic approach so it will take those into account within its range of possibilities. You cannot say whether it's in or out; it's both. There are cases that are in and there are cases that it's out but in most it's in.

------------------------------
 Nathan Piper,  RBC Capital Markets - Analyst   [18]
------------------------------
 Thanks for the clarity. Second question is more the philosophy of the Company and I think you have touched on this already. But are you up for developing SNE or realistically on the timelines you've put out is that a sort of one to two-year view before you farm down hopefully in the best possible environment, hopefully an improving oil price and all the rest of it, but is that the timeframe we're talking about? Because otherwise you're on the thick end of what could be an $8b to $10b development so philosophically --

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [19]
------------------------------
 Yes, I think you'd never want to -- as you know, Nathan, from the past, at times we've seen the developments right the way through, at times we've sold out before. And I think you'd never want to tie yourself to we will definitely exit before the development or we will -- because there may be any number of scenarios. You may do that; you may stay in for a percentage that's fully carried. You may stay in for a larger percentage and get available debt funding against what's a very attractive development I think. So it's very difficult today to give you a clear timeframe on the timing of monetization.

 But back to your philosophy point, the philosophy is to monetize and I think our track record on that speaks for itself. So that remains the core focus for us but we've got to be opportunistic in the timing of that to get what we believe would be the best deal for shareholders. But in the meantime we give ourselves the capacity to stay in for as long as is required.

------------------------------
 Nathan Piper,  RBC Capital Markets - Analyst   [20]
------------------------------
 That's clear. Thanks.

------------------------------
 James Hosie,  Barclays - Analyst   [21]
------------------------------
 Thanks. It's James Hosie from Barclays. Just your partner in Senegal, ConocoPhillips, it said it's undertaking a phased exit of its deep water portfolio. So could that impact any plans (inaudible) may have for 2016 drilling?

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [22]
------------------------------
 No. I think you're right, that's what they've said publicly. I think with us there's been absolute alignment in getting after these wells. If you mean could it slow things down, no, we see no evidence for that whatsoever.

------------------------------
 James Hosie,  Barclays - Analyst   [23]
------------------------------
 Okay and just another question on the UK North Sea. You talk about the cost savings that you've achieved so far and going forward. Can you elaborate exactly what elements of the Catcher and Kraken programs you're seeing those savings achieved and is it just contingency being released?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [24]
------------------------------
 No, it's not contingency being released and there's two things I suppose. There was an underspend on both projects in 2015 which relates in part to drilling being ahead of schedule but actually just operationally the joint venture has overachieved in 2015. In terms of reduction to the CapEx going forward, the operator on Kraken has announced something specific. Clearly, we're working on the same initiatives on Catcher. On Kraken it effectively relates to pushing down contractor costs.

------------------------------
 James Hosie,  Barclays - Analyst   [25]
------------------------------
 Thanks very much.

------------------------------
 James Thompson,  JPMorgan - Analyst   [26]
------------------------------
 It's James Thompson from JPMorgan. Just a quick one on the options. Obviously you're only three weeks away potentially from drilling the first option. What prospectivity have you got that's drill ready or is it another well in SNE next?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [27]
------------------------------
 Essentially, the focus is still on SNE and that's where most of the discussion is focusing at the moment, quite rightly. I think with the huge amount of data that we're collecting, just making sure that whatever well it is we drill next and whenever it is, that we make sure that the results from it are going to be the most meaningful. So that's the discussion that's going on at the moment.

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [28]
------------------------------
 (multiple speakers).

------------------------------
 James Thompson,  JPMorgan - Analyst   [29]
------------------------------
 And just in terms of the Bellatrix well, you drilled into similar reservoirs in the SNE-3 well. Could you give us any idea about the rock quality in those intervals?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [30]
------------------------------
 It's similar but it's probably not the same because we have different seismic responses between the two. So we do see the same sand quality. So sand quality doesn't seem to be the issue; it's about how much of the sand is there and of course what is the fluid fill. So it is very much open to exploration at the moment but the amplitude anomalies that we see around Bellatrix are significantly different to what we've drilled through before at this level. But we're not yet sure what that means; nobody's yet drilled into these rocks before with these amplitude characteristics.

------------------------------
 James Thompson,  JPMorgan - Analyst   [31]
------------------------------
 Thank you.

------------------------------
 Kate Sloan,  Macquarie - Analyst   [32]
------------------------------
 Thanks. It's Kate Sloan from Macquarie. A couple of questions on Senegal. Firstly, your partner FAR has come up with a much more bullish number on 2C resource. Can you talk a bit about the differences in your key assumptions there and what would you need to see to get up to that 468 number I think it is?

 And secondly, could you provide a split between the upper and lower reservoirs for that 385 you've come out with today?

 And then finally just on Bellatrix, could you talk about the -- I suppose James addressed it slightly but the key risks there and also the risk of that being gas in that reservoir?

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [33]
------------------------------
 It's all you, Richard.

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [34]
------------------------------
 Yes okay. So I'll take the last one first because I can probably remember that easiest. And clearly we have seen both gas and oil within the SNE accumulation. What we have also seen is a series of -- it's a layered reservoir. Although we have a common contact in there, we also see some inter-formational seals. So it could actually be a mixture of gas and oil; it could be all one or -- we actually don't yet know until we -- because we haven't drilled through the rocks of this particular age with these amplitude features in. So it could be a range of things there.

 Going back to the first question. The fact is that we're pretty early stages of appraising what is if not the largest discovery made in 2014 certainly one of the largest in the world. It occupies a very large area, potentially at the very uppermost top seal perhaps encompassing an area of well over 300 square kilometers. To put just three or four wells down in that and expect us all to arrive at exactly the same answer would probably be a little bit optimistic and unusual. And clearly if you give it to 10 different geological companies or 10 geologists, you will come up with a range of numbers.

 We both have wide sets of numbers. We're very, if you like, pleased that we're moving in the right direction. We've only incorporated as yet the numbers that we feel comfortable from the first of our appraisal wells. The second well has come in rather different and mostly better than we expected there. So there's quite a lot of room for maneuver yet and so I can't comment exactly how they've got their numbers, I don't know, but we're quite confident where we are at the moment and the way that we'd like to move.

 We haven't, coming to your second point, split that between the lower and the upper. What we know is that just from a gross rock volume it's simple geometry really. The larger area of the field in there, the larger volume of the field, is in the upper reservoirs. And so overall, particularly when we get to the 2C and 3C numbers, an increasing proportion of recovery will be coming from that area. And that's why it's so sensitive; you just need to have a change of depth conversion by a couple of meters here and there and that makes quite a big difference to the area. You then have a change of perhaps recovery factor, even just 1% or 2% there. That makes a huge swing to the numbers that you put into what is a stochastic estimation. It's very easy to come up with different ranges at the moment.

 What you normally expect in a field appraisal is you're looking to narrow these numbers down. Ours are just moving up at the moment. That tells you we're in the early stages of appraisal. So a nice set of problems to have actually but we're working on it.

------------------------------
 Kate Sloan,  Macquarie - Analyst   [35]
------------------------------
 Thank you.

------------------------------
 Thomas Martin,  Numis - Analyst   [36]
------------------------------
 Hi. Thomas Martin from Numis. I have three questions if I could. First of all, on your map slide with the aerial extent of the field, I think today your resources have gone up. I thought it was actually 17% when I got the calculator, 17%, 20%. It looks like the area has increased by greater than that amount by eyeballing it, maybe I'm wrong. Has there been a change in estimates of oil in place per square kilometer or anything like that between the post SNE-1 and post SNE-2 interpretations?

 Second question was on the development side of things, number of wells, that sort of stuff. Will you need to drill these narrower clastic horizons with separate horizontal wells and does that have an implication for increased well intensity as you go further up the resource range? And could we perhaps see a phased development?

 And the final question was on North Sea OpEx-related things actually. You've spoken about the CapEx reductions. I guess there are some fixed elements in the CapEx, contracts negotiated in advance. On the OpEx side of things I guess there's some leasing of vessels. But is there work being done on the OpEx side to reduce the OpEx?

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [37]
------------------------------
 James, why don't you cover off the North Sea first?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [38]
------------------------------
 The obvious answer is yes. As you say, a portion of that OpEx is they're both FPSO developments. There's FPSO lease costs where there's obviously less room for flexibility. But in terms of the rest of the cost base there, difficult to forecast exactly where it's going to be and what the climate in Aberdeen is going to be over a longer period but clearly we see downward pressure on that in the nearer term and that's reflected in the nearer term if you like all-in production cost that I guided to today.

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [39]
------------------------------
 Going back to your first questions, essentially the field at SNE is a very low relief field. We have a pretty consistent oil slab, if you like, of around about 100 meters give or take. All the wells have come in very close to that. But obviously as you get closer and closer to the edge, the very edge of the field, it gets less than that and eventually to zero. The bigger the field gets probably the less dense the hydrocarbon if you like per square kilometer that's going to come out of it overall.

 We have taken that into account in our estimates at the moment but obviously things keep moving as every well we drill will bring us new information in that regard. It's -- as we incorporate SNE-3 the field will get even larger than that so the key is that wherever we're finding these reservoirs at the moment, the sand itself seems to be good quality, that actually the wells flow, which is a great start.

 But what we do know about the upper reservoirs which as it gets busy, bigger, become an increasingly large part of the field, then we know that connectivity isn't perfect in there, it's not simple slabs. What we can do though is we can see that within the seismic. We can see the changes there and we're targeting particular locations to understand what the seismic response means in terms of reservoirs.

 What we must find out is which direction do we drill our development wells in. Right now we're drilling vertical appraisal wells and testing vertical wells. That will not be the way that we develop the field. How many layers do we use to develop the field, which directions do we put those horizontal wells in, how long do we make the horizontal or low angle sections and how many do we comingle from layer to layer, those are the right questions to be asking.

 And that's why we have a fairly wide range on recovery factors at the moment because until we actually do some interference testing and get some hard data to actually constrain that understanding, integrating lots and lots of core data with lots of test data, lots of log data and the new seismic that we have over the core of the field, I can't answer them. But they're definitely the right questions to be answering. That's what we're trying to look for the answers on.

------------------------------
 Thomas Martin,  Numis - Analyst   [40]
------------------------------
 And sorry the final one. Is a phased development a likely part of it?

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [41]
------------------------------
 That is one of the things that we're considering indeed, yes. So if we tackle the easy bits first and then move on from there, yes absolutely.

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [42]
------------------------------
 One more question at the back.

------------------------------
 Tom Robinson,  Deutsche Bank - Analyst   [43]
------------------------------
 Tom Robinson, Deutsche Bank. Just a quick question. One of your peers last week talked about a new paradigm going forward for E&P reflecting obviously the lack of capital that we currently see amongst the type of buyers who you would be looking for. How do you feel this has changed your business model and possibly your timeline to monetizing asset? Thanks.

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [44]
------------------------------
 I think I thought it was an interesting presentation and a lot of what was said I think was absolutely agreed with. I think from our perspective not much has changed. In fact, if anything, whilst arguably every oil company has suffered in terms of share price the effects of low oil price environment, we've seen the benefit in our model, that balanced model, of the lower cost environment coming through.

 So has it affected our thoughts about how quickly you can monetize assets and so on? Yes ,for those assets that aren't particularly attractive or maybe have issues associated with them. No, I think, in relation to the right kind of opportunity. We still see incoming interests in relation to for example Senegal. That continues apace. And so I think from our model's perspective the whole point of it is it's designed to try and ride through inevitable fluctuations in the oil price cycle which we've all seen and we'll all see again over many years because history repeats itself. So I think the design is to try and survive that and in this instance to be able to profit from it.

------------------------------
 Daniel Ekstein,  UBS - Analyst   [45]
------------------------------
 Thank you. Dan Ekstein from UBS. Two questions, both on Senegal. Firstly on SNE, Richard, you've made the point a few times that we're still at a relatively early phase of appraisal in what is a very large field and there's still a lot more technical data that we need before we can think about presumably sanctioning a development. In the scenario that the next three contingent wells are drilled, would you expect to glean sufficient data points from those that you could start to think about pushing towards a project FID including all the interference testing etc.? Or do you think you might need to come back to it for further appraisal in 2017 or beyond?

 And the second question is on FAN, FAN-1. You mentioned in the presentation that the sand quality you saw was of considerably lower quality than what you saw in the shelf edge play. Is it realistic that sands of that quality in water of that depth is going to be commercial? And what's the carrying value of that well considered for impairment testing at year-end? Thanks.

------------------------------
 Richard Heaton,  Cairn Energy PLC - Exploration Director   [46]
------------------------------
 I'll try and answer the one on FAN-1 first. What we have been doing since the FAN-1 discovery is remapping that play. When we drilled FAN-1 it was a well position designed to encounter as many if you like different what we hoped were sand layers as possible at one location in as up-dip a location as possible. What the well fortunately showed us is that there were multiple sands, in fact multiple oils. Not any of the sands were particularly marvelous in quality at that location.

 When we map them away we can see that some of the sands that formed the most important part of the accumulation, they do seem to thicken and improve away from that location. To what extent, until we actually consider putting a well in there, we won't know, but clearly that's the key question to ask.

 Now as a standalone I think it's not the most likely thing to be a standalone at the moment, but as a tie-in potentially to a core project, that might be a different answer altogether. And we're still working through that. So away from the well location both the north and the south we see much -- what we believe to be much better seismic data.

 So it's still being worked through and that's the position at the moment. So nothing firm at the moment but it is being evaluated as part of the block-wide evaluation plan and there are additional prospects of a similar nature to the south, as you'll see on the maps.

 In terms of the appraisal well number in SNE, then I think the very minimum we have always thought would be needed would be about five wells for something that we saw originally. As the field gets larger, of course then the question comes well will you need more appraisal wells. It's a very obvious question. It's quite possible that we will. What's fortunate though is that the wells are relatively easy to drill.

 Actually we're well under budget at the moment. These are -- if you don't actually do any coring and you don't do any testing and simply drill the well and move away, 30 days is really all it's taking us at the moment. So if you look at that, that is not a difficult complex or expensive well. That's on the one side.

 On the other then there's the approach that was mentioned as do we just do a phased development and concentrate on a core to begin with, and in that case if you're doing that maybe you don't need any more wells at all. So they're the right questions to be asking at the moment and that's because it is early in the appraisal stage. Those are the things that we need to work out. What is the most efficient, effective, cost effective way for us to get this project moving within a sensible timeframe. That has to be agreed of course between the partnership and the Government as well. So answers that we're seeking ourselves.

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [47]
------------------------------
 Impairment?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [48]
------------------------------
 I guess on the -- Richard's answer effectively answers the question, the technical point about impairment testing. Clearly, we consider all of our carry costs for impairment testing but whilst the base case and reasonable assumption is that there will be continued work and continued investment in that, which is true for us and true for our partners, then (technical difficulty).

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [49]
------------------------------
 One last question.

------------------------------
 Mark Wilson,  Jefferies - Analyst   [50]
------------------------------
 Thank you. It's Mark Wilson at Jefferies. You're very specific about Cairn India liability being limited to the subsidiary, the Indian subsidiary.

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [51]
------------------------------
 Yes.

------------------------------
 Mark Wilson,  Jefferies - Analyst   [52]
------------------------------
 I think it's fair to say over the last few years Indian news flow has surprised negatively whenever it's come out so can you just emphasize quite why you're confident that that liability is limited to the subsidiary?

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [53]
------------------------------
 Sure. James?

------------------------------
 James Smith,  Cairn Energy PLC - CFO   [54]
------------------------------
 It's obviously -- we make that statement based on pretty robust legal advice. The only subsidiary of Cairn or the only assessment, tax assessment that we've received is against Cairn UK Holdings Limited, a subsidiary -- a 100% subsidiary of Cairn, and the only assets of that are effectively -- or the principal assets of that are the shares in CIL that we continue to hold and then dividends which are effectively held in escrow which we haven't received, so held on the same basis.

 And so those are the only assets that if you like the Indian authorities can have recourse to in ultimately trying to enforce that tax assessment. There isn't a mechanism under Indian law or under UK or international law for them to look elsewhere in the Group.

------------------------------
 Simon Thomson,  Cairn Energy PLC - Chief Executive   [55]
------------------------------
 Okay, I'm conscious of time so thank you very much indeed for coming and I look forward to coming back to you with further news in due course. Thanks.




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