Capricorn Energy PLC

Okay. Good morning, everybody.

Welcome to Cairn’s results presentation. I’m Simon Thomson, Chief Executive.

With me are Paul Mayland, COO; Richard Heaton, Exploration Director; and James Smith, CFO. As usual way, we got a presentation to run through with you this morning and we'd be very happy to take questions at the end.

It's being webcast, so if you do have a question, there will be microphones to be passed around and please state your name before asking a question. There aren’t any scheduled fire alarm practices, so if an alarm does sound, you can see that the exit is to the rear and the mustering point is out in Lincoln's Inn Fields.

Okay, turning to the first slide. Over the last year, we have seen positive progress across our assets and operations, and that leaves us well placed for continued delivery of our balanced business offering.

That business offering is underpinned by three core pillars. The first, near-term production and future development options.

As you’ve seen from the announcement this morning, both Kraken and Catcher are on track and significantly under budget, and we are looking forward to first oil from Kraken in this first half. And in addition - and Paul will touch on this - we now have line of sight on Skarfjell, three concept select and we are looking at FID at the end of the year.

And as a reminder, we've got a 20% interest in that. It's a 100 million barrel field, if you like, a homegrown discovery, and will add to our strong cash flow position in the future.

In terms of the second pillar, our exploration portfolio continues to offer significant growth opportunities. We remain really excited about Senegal and about the options for further exploration success that we see in Senegal, and Richard, in the presentation, will outline a number of the prospects that we see as drilling candidates.

And of course, as you’ll all have seen from the announcement, we’ve already added another well to the program, VR-1. We’re already on location on that well.

It’s a dual objective appraisal and exploration. And we hope that actually that will be the first of a number of wells to be added into these sequence.

But in addition, we’ve expanded our position in the Atlantic Margin and in the Barents. As you will have seen, we’ve taken on a couple of farm-ins in Ireland, one of which gives us exposure to a high impact well this summer.

And in the Barents we have moved forward and taken more acreage, and some of that acreage is as operator for the first time in that part of Norway. So a number of exciting things moving forward in the portfolio to generate more in the way of longer term growth opportunities.

And the third pillar really underpins all of that delivery, our financial flexibility. So we funded not only for delivery of all of our commitments but also for further growth within the portfolio, whether in Senegal or elsewhere.

Cash resources at the end of last year were $335 million and undrawn facilities peaked our availability between $350 million and $400 million. But in addition, as you will have seen, as James will describe, we've entered into a number of financing facilities to ensure that we retain that financial flexibility that ensure that we are able to deliver a line of sight on continued exposure to exploration upside in the portfolio.

And I'm thinking important point, the Indian dividends is sign of progress in tax disputes situation, which in itself is moving forward. As you will be aware, we've launched our - us stating the claim.

India have now launched their defense and a final hearing has been fixed for January 2018. So progress in the arbitration itself, but also as a result of that progress, confirmation of the release of the dividends $51 million.

And all of that added to the cost savings that we've seen across the Group ensure that we have enhanced financial flexibility. Moving onto the next slide and just a brief few words on Senegal, where we can report continued success in the rapid appraisal of the Senegal field.

It's worth remembering that we've now drilled seven wells in three years. So following the two basin opening discoveries at the back-end of 2014, now five successful appraisal wells.

In the 2015/’16 drilling campaign, which was the second phase of drilling, the four appraisal wells which were all completed ahead of schedule and under budget helped to establish the current 2C resource base of just under 500 million barrels and the oil in place of just under 3 billion barrels and also allowed us to commence the development planning. We are now in the third phase of drilling, utilizing the Stena DrillMAX, attractive rate, $185,000 a day but it's more than the rate, the rig is performing extremely well.

We have a very flexible contract, as you know, as we've earlier disclosed and we are very pleased with performance. In fact we are already two weeks ahead of schedule and being on location on the VR-1 well.

And all of that ongoing success does provide us options for commercialization. So what we see our number of milestones that are potential value defining events, whether that's concept select, FEED, FID or first oil.

And I think that's important when you move onto the next slide on confirmation of Cairn’s business model. Our options for commercialization can be built within our existing model.

We don't need to go anywhere else to achieve that. So Kraken and Catcher on plateau 25,000 barrels a day, sufficient to fund our future exploration activity but also to reinvest in sustainable cash flow generation from within the portfolio.

Skarfjell is an example of that. Senegal is also as a potential example of that.

But those projects also give us the flexibility to arguably developed or to be partially or wholly commercialized, leaving us with sufficient production to reinvest in that future exploration and ensure a self-sustaining business model, because at the end of the day what we want to do is to deliver further exploration upside but also select value realization events and potential future returns. And on that, I'll hand over to Richard.

Thank you, Simon, and good morning, everybody. I'm going to start off really explaining a little bit about the wider strategy, look at the wider portfolio but actually spend most of my time explaining about Senegal, and particularly that side of the latest operational results before I hand over to Paul.

And of course as Simon has set out what we are trying to do is create growth, create the story through exploration. That's long been our strategy, continues to be so.

Our current portfolio is one that is based around the geological theme around the Atlantic Margin. That provides you with some commonality of the geology and the plays that you're looking at, all part of the splitting apart of the continent of Pangea along there and we’re focusing on passive margins and riffs.

It’s most common place, shared learning that helps us hone our skills. It also allows us within that very wide area to have a mixture of basins of different risks, mature, emerging and frontier basins, and of course our team has had success there, so it knows what success looks like and it's a strong exploration team.

We've built a good portfolio, good platform. We still need to build more and come onto the latest building that we've being doing very recently in Ireland but it is part of a wider approach.

Of course we've got good acreage position. I'll have to update the number of kilometer squares now for this morning's news, but we've got good resources there in Senegal and elsewhere.

We've obviously got the two fields in terms of the production that will come on in 2P number there. That allows us to keep exploring, keep looking for things, keep a sustainable model.

Everywhere we are looking, we are looking to build good positions, where if we have success in exploration, you can continue to build, and that requires obviously a strong technical position, you look the technical attractiveness of the basin, but also good fiscal terms to make sure that it's always got value there. So we've been building a portfolio across this time.

Simon has talked about the Barents position that we have been building and we now got operatorship in Norway including in the Barents. We continue to apply the license around there and take part in drilling, also in the U.K., obviously more mature there.

Got positions in Morocco, Malta. We've been building in Ireland, and I'll come onto that in a little while but spend most time of course in Senegal.

It's a strong platform we are looking to add. We have added in Ireland, so this is entirely in line with our strategy.

We've been in the basin in the Porcupine for some time now, starting out in the north Spanish Point area. Last year we picked up 16/18 license option there, which is very competitive round last year of 40 companies bid.

We bid for quite a number of pieces and this was the one we were awarded. What we've announced today is that we are farming into the area to the south 16/19.

We'll take operatorship and 70% there. Europa Oil awarded that license.

We’ll be shooting seismic there this summer. And then to the south further on FEL 2/14 Providence-operated license, well Druid, Drombeg is drilling there.

It's a very large prospect. We like this basin.

We think technically it's got all the elements for hydrocarbon discovery. Many wells had shown reservoir seems to being the issue for most of these but it's got good data, very large prospect.

We see perhaps a P-mean of 600 million barrels or 3.3 Tcf. There is some phase risk there at Druid and underlying it Drombeg about 250 million barrel mean prospect size there.

So this is a big hitting well. Very important, we are taking a 30% interest and that will be drilling later this summer, so very exciting and entirely in line with our strategy.

I'll now move to Senegal. Obviously we've been there now since our discoveries in 2014 being very active.

We have a growing story there. SNE field is where we’ve undertaken most of our activities and indeed I’ll come onto explain the most recent of those shortly.

Just to remind you, our 2C, so that’s our proven and probable resource estimate by our auditors, ERC, that’s 473 million barrel feature. So that's the anchor project, and of course there is a good deal of exploration around that.

I'm going to focus first on that exploration. We have a large license area here over 7,000 square kilometers but we always saw that there were multiple plays in this basin.

We've started to test those. What we are about to do in the VR-1 well is test this yet more with more explorations.

And Simon said that that's on location today and will start its activity today. But what you can see is once the anchor project of SNE is established, there is a whole raft of prospects around the area which can be tied back.

They have great value. Our job as part of a three-year evaluation program that we are conducting across the whole block is to try and secure as much of that value as we can before February ‘19 and a series of drilling phases.

We are in that second phase now. They have - it's a pretty exciting place to be.

It's very unlikely that's with the first two wells ever drilled in this part of the basin that we found all the hydrocarbons that they are going to be. Every well so far has been a success and it looks very exciting.

So the VR-1 well is actually dual objective well, so it is an exploration well. And if you can recall, the SNE-1 well, which was the second well we drilled, that was the discovery well of SNE field, it at the time was a dual objective well.

It found that the sands in the upper levels and that was a success, it didn’t work at the deeper carbonate level. And when we now map that, it's no wonder it's probably outside of closure, certainly a long, long way down deep and our new depth conversion shows at the crest of these Aptian carbonates is where we are drilling it now at VR-1.

It's a multi-target carbonate play. We saw in the - well, we drilled SNE-1.

We did see reservoir, we saw seals, we saw hydrocarbons in the rocks there, residual hydrocarbons. So it's clearly a working system.

And here we have multiple layers, multiple seals and the consolidated geology success there about 30% overall. Each layer is much riskier than that but together there is the degree of independence.

Beauty of this well is it’s right beneath the SNE field but a very far western edge of it. So where we drilled this well was five kilometers west of the line of wells that we've been drilling in SNE there, SEN-1, 3, 5 and the Bellatrix well.

So it's a good appraisal well away from that line and it's focused mostly on the lower reservoirs where we've seen them, they are the better quality reservoirs. They will be very susceptible.

We expect a good water for that behavior and good recoveries. And so it's important in gathering this data point this faraway to support what would be access to the easy oil in the first phase of any development in SNE, so pretty exciting well.

We are well ahead of schedule, as Simon has said, on the drilling. So this can be very effectively and efficiently drilled, gathers a lot of new information, both to help us with the SNE development and also obviously any further development of deeper oil there underneath the main field.

It's not the only well we may drill. That's being confirmed, but clearly with the well and rig program that has now three firm wells but still a further six individually exercisable options with a very efficiently performing rig, then the joint-venture is very keen to make sure we explore the whole of the license and a couple of the examples that I’ve - some of which described before.

This was known as the Sirius Prospect. We’re calling it SNE North now.

More than likely in our view that actually the oil/water context is the same context that we see in SNE, whilst will stretch to the north here. This target will look mostly at the upper reservoirs.

We've even got some further reservoirs we've found with gas-bearing in the number of the wells in SNE now, possible that they are gas-bearing here. It's also possible at this location that they may have some underlying oil as an oil rim [ph].

So multi-target well. Again, very valuable to be added in as a satellite to any SNE core development.

And then a further well, this is exploring again into the slightly deeper water, the deeper plays. The FAN-1 well was our first well in Senegal.

That was a discovery. Had a long column of hydrocarbons, a series of columns but the net reservoir there was not so good, perhaps only 20, 30 meters.

But as you come slightly shallower, the same plays may develop much better reservoir characteristics. We will drill some of the same sorts of rocks that we saw in FAN-1, so to some extent it’s helping appraiser a wider area, but essentially this is an exploration target where you’ve got mostly new sand input points, new FANs, new layers.

It’s multi-target well. We've just firming up the potential location and obviously with both these Sirius or SNE North and the FAN South locations, something the joint-venture will be voting on very soon.

Finally I'm going to talk here two slides about the very latest results. SNE-5 and 6 are part of an interference test pad that that the joint-venture has long wanted to conduct to demonstrate the connectivity in the upper reservoirs, and the upper reservoirs are 400 series sands as they are called.

They are the bulk of the oil in plays but when we saw the test results on SNE-3 last year then it showed us that there were connectivity issues to be resolved by further interference testing and that's what we are conducting now. We can see that wherever we flow these reservoirs, they flow at tremendous flow rates.

They have very solid flow rates but the pressure drops that we saw in SNE-3 after testing indicate that the connectivity of those reservoirs is not as good as the lower 500 series ones that we tested in SNE-2. And so SNE-5 finished that well just the other day.

Again very solid test results here. And the key is not the headline rate of 4,500 barrels a day, which is great.

It's the length that you can produce these reservoirs and see very fairly modest declines in pressure. The importance of doing both 5 and 6 together is that we can start to understand the way that the sands are connected, not just the level of flow from them.

We've added in the second part of the flow here a further reservoir, which was slightly higher sand that has never been tested before and that added a very significant amount to the flow rate as well. So this was a very useful result.

What we can see in the reservoir and there is some complicated diagrams here but essentially this is a core taken from one of the reservoirs that's one of the upper reservoirs, very high quality sand. We've got lots of data from that.

We're integrating that with a very complex series of 3-D seismic images, and you can see trends in this seismic running both in this direction but also in an orthogonal direction across here. And our expectation from placing wells 5 and later 6 here is that we will be - we've got good flow rates from this well.

We have flow rates from SNE-3. We’ll come back and tell SNE-6, and what we will observe there is how the things connect between a big flow rate for about 10 days from SNE-6, we'll observe the results in SNA-3 where we've put pressure gauges there, and also in SNE-5.

And we think they’ll preferentially move to SNE-5 if our reservoir model is right based on the seismic and core data. And that will be important for how we place the development wells, what direction we put them in?

They will be horizontal wells for development or near horizontal, not the vertical wells we see here, to connect up huge amount of sand and get very high flow rates. Wells are probably the largest part of the cost of any development, and so the fewer wells you have put in, the more profitable any development will be.

And with that, I will pass over to Paul, who will explain just how we may go about doing the development.

Thanks, Richard, and good morning, everyone. So I'll provide an update on our operations and also our developments, and will start first with Senegal.

So firstly with the drilling operations. We have been pleased with the results of SNE-5, both the logs and the tests, as described by Richard, but also the overall drilling and testing performance.

The operations have been conducted incident free, very low non-productive time and overall a significant improvement compared to prior wells. An illustration of that is shown on the diagram in the top right where the red dotted line is the original discovery well, SNE-1, which as Richard said, when done into the underlying carbonates.

That was the last well in the four-well program conducted across Morocco and Senegal in ‘13 and ‘14. The black line is the SNE-4 which was our last well drilled in the previous campaign, which was drilled just down to the clastic sandstone reservoirs.

And the purple line shows obviously the performance on SNE-5 and the DrillMAX. And although with similar times obviously, we've actually conducted in the drilling operations effectively in two to three weeks, so that really is the equivalent time compared with the prior wells, which were a similar evaluation but then subsequently we conducted about three weeks of testing, and so we are very happy with the performance.

We are effectively halving the prior times in terms of drilling and evaluation. It's also worth mentioning that obviously we will incorporate that into development well planning.

A lot of that will be directional work rather than vertical but the overall performance is good. We are also delighted to have Woodside on board within the joint-venture and that's working well and overall we plan to play to the respective strengths of both companies.

An FPSO solution, as described previously, has been endorsed by the joint-venture as the most appropriate solution to take this project forward and we are developing the overall contract strategy. And as I was saying that we’re sort of moving forward with pace in terms of our development planning in 2017, we plan to conduct further metocean data gathering and conduct an extensive geotechnical seabed survey across the SNE area.

And as Richard has described, clearly the results of the remaining exploration and appraisal wells will determine the overall scale and phasing of the SNE anchor project, as we describe it, we remain on track with the previous timelines that we outlined as early as post discovery in 2014, which should see us on a journey to deliver first oil in the window of 2021 to 2023. What are the next steps there?

We are really - we are going to finalize the concept select this year and formally plan and prepare to submit the evaluation report, which will formalize the end of appraisal. And then relatively quickly thereafter, in 2018, we would anticipate to finalize and submit the Exploitation Plan following completion of our competitor FEED exercise and then take a final investment decision.

The targeted production rate and the timeline for first oil remains unchanged at this stage, as described in the diagram, 100,000 to 120,000 barrels a day plateau rate and first oil in that window describe there. So that's our situation in Senegal.

It's probably worth just touching on quite a good publication, which was made by the OGA about project execution, before we move on to the North Sea, last week and there were three things that were mentioned in that clearly defining the project scope prior to project sanction, keeping the project as simple as possible and improving the cooperation between the companies and the stakeholders. And obviously that is very high priority for us in Senegal.

And to some degree, we've seen a success of those ingredients in our North Sea projects. If we put it in some context at Kraken and Catcher, the above slide shows a list of projects ranked by size, as we broadly saw them 2012/2013 when we first entered them.

The current status is also shown and described below for each project. And we are pleased overall that Kraken and Catcher have actually progressed really well, both on an absolute and relative basis, and we are really encouraged that over the next 12 months we will see both projects come on stream and ramp up to plateau production.

So firstly, Kraken. I think you're relatively familiar with this project operated by EnQuest, target first, Plateau rate 50,000 barrels a day.

The drilling and completion is going well and all of the subsea work, particularly last year, went very smoothly, such that we are ready for first oil. As EnQuest have announced earlier this year, the FPSO is now on location, has moved, all the risers are approved in [ph] and commissioning is ongoing.

And commendable to EnQuest working with us, we’ve managed to deliver $700 million of gross project CapEx savings compared to the FID case in 2014. Few good pictures showing in the diagram there.

In terms of Catcher, making steady progress there as well. The target first oil before the end of the year.

Plateau production is 50,000 barrels a day and the drilling also has gone really smoothly, and on the three accumulations which are Catcher, if you remember rightly, Burgman and Varadero that collectively form the Catcher project. And the reservoir quality, and in particular, the productivity and injectivities of those wells have either met or exceeded expectations and there is a strong correlation between reservoir quality or permeability and recovery factor.

So we are naturally quietly encouraged about how these fields are going to perform. But we are not going to ahead of ourselves.

The FPSO is still progressing well. It's in the Singapore yard and we expect that to depart later this year.

And a similar story in terms of savings premier and the partnership, working together with the service companies and overall performances resulted in a $650 million gross project saving compared to the FID number. And last year in 2016, we made a small discovery called Laverda and that license has been extended with the option of possibly developing that via the Catcher infrastructure as a tie-back.

And lastly, as Simon mentioned, but no means least, the Skarfjell project in Norway which fits well within our overall portfolio and is likely to see the commercialization on organic resource discovered by Cairn in 2012 with our joint ventures, partners in Norway. The joint-venture have selected a tie-back as the best economic solution and it was close-run with some other options, and we are working together to deliver a well-defined project with a low breakeven price and we'd anticipate further cost reductions associated with this project in 2017 as we look to move it forward, in what is still remains a relatively weak market.

This is a core area for Cairn where we hold multiple licenses, as shown in the diagram on the right, and we would expect to participate in one to two exploration wells a year in this area. So in summary, Senegal is making good progress as we move through appraisal and into the final stages of Exploitation Plan preparation, and subsequently of FID.

U.K. North Sea projects are drawing close to first production, and we anticipate Skarfjell will move forward to FID by the end of this year.

At this point, I will hand over to James.

Thanks, Paul, and good morning, everyone. So next few slides are set out the funding position, that effectively underpins that investment program that Richard and Paul have outlined.

As you've already heard, 2016 was really characterized by strong execution both on our U.K. developments and also on the Senegal appraisal.

And the outturn of that is clearly costs being significantly under the original guidance during last year. In addition to that strengthening, we've added further sources of funding to increase flexibility, which I'll come on to talk about in a minute.

2017 is clearly going to be an important year as we move into cash flow generation, closing out that cycle in the regeneration of the business. When that cash flow comes on stream, they are high margin barrels.

As we guided previously, Kraken all-in OpEx will be about $14 a barrel on plateau. Looking out beyond the end of this year over the next 12 to 18 months, clearly there were a number of catalysts both in terms of valuation but also in terms of further strengthening the robustness of the balance sheet.

So by 2018, we’ll reach plateau production in the North Sea from Catcher and Kraken of 25,000 barrels a day. We'll be taking Skarfjell through final investment decision next year.

And clearly, as Paul has talked about Senegal, we’ll also be moving into its Exploitation Plan in that year as well, and we have the financial flexibility as you've seen with today’s announcements to be looking at new ventures and further exploration as well. So looking first to last year's cash flow.

The opening cash position, $603 million. You can see the most substantial numbers on this page relate to the Senegal appraisal activity and the Kraken development.

The Senegal appraisal program was four wells last year, that $105 million was effectively the original budget for the three committed wells. We expanded that program to be four wells effectively for the original cost estimate of three.

And on Kraken, a similar story. The original cost estimate for last year for Kraken was $200 million net to us and clearly delivering at $125 million, which is really mostly to do with savings and the release of contingencies rather than deferrals, so true savings as it were, is a pretty significant achievement for the joint-venture.

Other items on the page across the U.K. and Norway and the International.

That's two wells in the U.K. and Norway, and earlier stage exploration activity across the rest of the portfolio.

The all-in underlying cash G&A number, about $12 million in line with guidance, and you can see in net against this $36 million Norwegian tax rebate we received at the end of the year, that gave a closing cash position of $335 million. Looking forward now to this year on the capital program, starting off with the $37 million effective working capital position at year-end, so that's cash outflow this year for activity that was undertaken last year that predominately relates to Kraken activity, which obviously carried on over the year-end.

In terms of the U.K. developments, as we've already talked about the savings, we anticipate $55 million this year on Catcher, taking it towards first oil.

That's a reduction of $45 million net to us on the guidance we gave six months ago at the midyear 2016 results. And on Kraken, a similar story, $95 million.

That is a $75 million reduction in the original guidance we gave through to the end of 2017. And those savings result from effectively successful subsea installation on both fields, which enabled us to release the contingencies and allowances related to that work stream.

Drilling efficiencies, so the run rate on drilling has been significantly lower than originally budgeted and there is also some FX effect in there for the sterling costs. Senegal, $95 million, that includes the three wells, so both of the interference test wells that Richard was talking about, plus VR-1 appraisal and exploration well that we are on location with.

That compares with an original guidance of $85 million for just the two wells. So again three wells largely for the original anticipated cost of two.

And included in that number is also various predevelopment planning and study activities that we'd be carrying on to take us to the Exploitation Plan submission in 2018. The International E&A number there includes $30 million for the Druid/Drombeg farm-in that we announced this morning, and that together with seismic activity and other early-stage exploration activity across the U.K.

and International portfolio, represents effective the total of the committed CapEx through to the end of this year. And the final bar there, you'll see we've included $50 million, which represents a two further exploration wells subject to joint-venture agreement in Senegal, as Rich has alluded to, mostly those could be SNE North and FAN South, and that $50 million represents the two wells net to us.

So on this slide, we are looking at the sources of funding that underpin that capital program, and as Simon already alluded to, we have strengthened and diversified those sources of funding during the last few months. So the only cash positions I mentioned, $335 million.

Our reserve based lending facility which we put in place in 2014 to underpin the Kraken and Catcher developments, remains undrawn. That's a $575 million headline number facility.

We expect at peak to be available in the range of $350 million to $400 million to fund those projects with approximate availability by the end of this year of $210 million. That's really driven by the CapEx program on the fields, so it's effectively a project finance facility where availability is shaped to the CapEx program, hence the availability sort of stepping up through time.

We expect to receive during the year $26 million Norwegian tax rebate in respect of exploration activity undertaken in the country in 2016. And we've recently put in place a NOK 500 million facility, that's roughly $60 million, to finance those tax rebates against future activity in Norway to effectively create a more efficient financing base for exploration activity in Norway.

We also announced this morning, as you will have seen, a FlowStream financing. This relates really to the 4.5% stake that we acquired in Kraken from first oil early in 2016 for notional consideration.

So it's $75 million against a royalty or stream against that 4.5% interest that we acquired and that stream will step down to 1.35% once FlowStream is achieved at 10% return on that $75 million financing. The only recourse is to that production interest, and as I said, it's effectively for us a clever way to finance that 4.5% acquisition, which was for notional consideration and the proceeds here are significantly more than the CapEx associated with that interest.

As Simon already said, we have through the international arbitration process on the Indian tax dispute, now confirmed that the dividends that have not been paid to us to-date from Cairn India on instruction from the Government of India are no longer frozen, and we therefore - that's recent news that's come through, through to the process of tribunal, and we are therefore clearly applying to Cairn India for those to be paid as soon as possible. And the final line on the page clearly relates to operating cash flow, which will come on stream during Q2 and forecasting at the forward curve oil price of $52 for this year.

We’d expect that operating cash flow to be about $90 million from Kraken only. That doesn't include Catcher, which we expect to come on stream towards the end of the year.

And with that, I'll hand back to Simon to conclude.

Thanks James. So in conclusion therefore in terms of strategic delivery, we have near-term production and future development of options within the portfolio, and as you’ve seen, we're very comfortable with the progression of activities in relation to those.

Our assets offer significant growth opportunities. We are obviously very focused on Senegal and excited by the continued exploration upside we see on the acreage.

We've increased our financial flexibility, that’s to reinvest in the existing portfolio but also to consider new venture activities that satisfy our strict screening criteria, and Ireland is an example of that. And I guess just finally, looking at the picture on the right, we retained the flexibility and the desire to put ourselves in a position where we can, at appropriate time, effect value realizations and potential future returns to shareholders because that is our ongoing business model.

So it's going to be a busy year ahead and we are looking forward to it. And with that, I'll hand over for questions.

There from down the front.

Thanks. It’s David Round from BMO.

So first question, I’d just like to understand what's driving the schedule of changes in Senegal, and why specifically VR-1 has moved on top of the list? I guess your partner put out a list of prospects last month.

I didn't get the impression it was a high priority back then. Two quick ones.

Just on, in terms of contingency on Catcher. Is there anything left?

And also I noticed the development CapEx on the U.K. developments had come down a bit from, I think, it was $170 million to $150 million.

Is that just phasing?

So I think just on the point about partners having - as is always the case, people will have different views on exploration upside on the acreage and that's for each person to come forward with their views. But Richard let me hand over to you in terms of the schedule.

Yes, I think obviously at the time that we had to commit to the rig, the partnership was able to conform that we needed an interference test. That's always going to be two wells and that was the two firm wells in the program.

I think we also knew that we were going to conduct some exploration activity, but it took a wider discussion to understand what the key aims of that were. And so once that’s been confirmed, then in makes sense for us all to move the schedule a little bit and it's more efficient for us to do so.

We get a double hit with this well, whereby it's really confirming some of the lower risk elements of the SNE field, at the same time as exploring potential oilfield right underneath that development. So there will be an impact on development from both of those points, and in fact, it gives us - additionally it gives us rather more time to evaluate the full pressure test results from SNE-5 to ensure that what we do in SNE-6 is optimized and that's rather than having to do it so quickly.

We still gather data even today from SNE-3 that we did last year because we have gauges down there. And as we understand how pressures are moving around in the field from all that information, it helps us to understand how better to potentially develop the field.

Paul, on the…

Yes, on the North Sea developments, the numbers we showed on the chart there were the comparisons to the last formal guidance we gave or detailed guidance we gave in August 2016. But you're right, there is further reduction based from the pre-close announcement we gave in January.

Overall - and you also asked about contingencies. Overall those reductions are a mixture of contingency release as subsea installations being completed and it's complete or substantially complete on both projects now and then also a reduction in the overall drilling costs, so clearly the all-in drilling costs is the number of services in addition to the rig rate and we’ve just see those come down significantly.

So it really is a true saving on both of them. You asked whether there was contingency remaining on Catcher.

There is contingency remaining, although substantial part of the original contingency related to subsea work which is now complete and therefore that's been unwound.

Okay. One from here.

Good morning. Nathan Piper, RBC.

A couple of nitpick questions but going to be a bigger one first. You talked about realizing value in SNE.

Is there some pressure on you to realize value in the next 12 months before operatorship naturally passes to Woodside? I guess, one way of putting [ph] is, you will obviously have most value in your stake in SNE with the operatorship than without it.

So does that provide some pressure to try and do something sooner rather than later? And then just to go with the nitpick ones.

On the VR-1 well, is there a bit of upside from the lower SNE reservoirs in the well you’re drilling there, could - after the depth conversion I think things were higher. So would that be able confirm some of that?

And then the other one is on the FlowStream. I think FlowStream managed $200 million deal with you, I'm not sure if you knew that, but could you maybe give a bit more color as to what the wider deal with FlowStream could be?

Yes. On the first point, no.

There is absolutely no pressure in terms of realization. And I think that's important point and why we are, I guess, belaboring the point on financial flexibility.

We always want to be in position where we have the option to realize value but no obligation. The initial will be in Perth with Woodside and Paul led the team.

There is a very good established already working relationship. I think they are very pleased with the way that we are going about with the exploration and appraisal.

They see the value add that we have in there and that may well continue, so no pressure at all.

And on VR-1, yes, by drilling so far to the west, we haven't yet drilled that far and our depth conversion can move things up and down, so we are choosing the position that says, look, this is what we expect. It will confirm at least the 2C number, but you do need to know whether - it could go up, it could also come down but it's a very important fact to actually nail because it does have an impact upon how you will develop the field.

You need to know that before you start. These reservoirs are the best quality reservoirs and we are aiming to try and water-flood them.

You need to know where to put the wells to make sure you do that water-flooding and that's why it's so important.

And on FlowStream, what we’ve agreed is the $75 million financing that I talked about, which is effectively ring-fenced to that 4.5% in Kraken that we acquired during last year, plus an option on up to a further $125 million financing, which would be in respect to the royalty across both Catcher and Kraken at our option and subject to various consents. So you can read about that in the financial review in the prelims today.

We are very pleased they wanted to headline with the appetite to do a bigger deal with us and clearly that's flexibility for the future. But what we've agreed - what we intend to draw for now is that $75 million against the 4.5%.

That's clear. Thank you.

Thank you. It’s Robin Haworth from Stifel.

Just a question on India. Just wondering if you could talk through exactly what the discussions were amidst the arbitration that led to the dividends being released, if you could, please?

Sure. James?

And just a follow-up on reservoir stuff. So how do you see horizontals - clearly you're planning horizontals for the development of SNE.

I was just wondering if you could talk about whether you need to drill one of those horizontals in the appraisal phase and how that might fit in the current appraisal campaign? Can you do that in 2017 for instance?

Thank you.

On the dividends, first of all, I guess it is not necessarily a comment on the wider case but it is an indication of the helpful forum of the international arbitration. So effectively we had a view, or at least our legal interpretation was that the dividend should no longer be frozen.

That was not something that was easy for us to establish in country with a tax department, given there was a sort of ongoing freeze on CIL paying them, and so we sought clarification on that matter through the international arbitration and India gave that confirmation through that forum rather than domestically. So that's the sense in which it came through the international arbitration.

Paul?

Yes, so on the horizontal wells or the high angles sort of 75 to 85 degrees through the reservoir section, that's probably our base case plan for water-flooding and particularly the upper reservoirs. It is an option.

We’ve obviously got a number of options and it's something that we are discussing with the partnership, which state have drilled quite a number of these in long laterals in the northwest shelf fields, so clearly they are technically comfortable with being able to execute this. We've always had this, as Richard described, two firm wells which is anchored around the interference test exploration opportunities that we would slot in as accordingly and that's what we've done, and also there is a consideration, as you described, a high angle well.

But I think both ourselves and the partnership would really want to look at the value of that information and see if drilling such a well was actually going to change the decisions associated with the development plan and while it’s going derisk before we allocate capital to conduct such a well.

Could you fill it in 2017?

Yes, if we were to execute it, we would aim to do in 2017. So it would probably be after the exploration wells are drilled.

Okay.

Stephane Foucaud, GMP First Energy. Few questions please.

Coming back to the VR well, so the deeper target is a carbonate, so arguably riskier, more tenure [ph] has been difficult et cetera. So taking this in consideration, I guess, one of the important factor to drill the well is the lower/higher quality sand.

So which would be a bit of - appear to be a bit of a change of strategy on why drill this well. So I was wondering whether if this was because you felt you need that well to support the development plan or perhaps Woodside coming in and there is a slight different view.

So I wonder whether if you can provide a bit of comment on that. Second question is there are various comments from the various partner, is Woodside not confirmed in the partnership, are they still risk-associated with it or legal discussion or anything like this, and if that's the case, could there be potential change in the partnership?

And lastly, it's a question on the resources at SNE. I think the gross number talks about 473 million but the 40% talk about 203 million, so it seems to be something like 10 million barrel difference when you adjust the 473 million multiplied by 40% compared to the 203 million barrels you're showing.

So again, I wasn't knowing whether it’s because you have increased more things since the [indiscernible] report has been made or if there is anything else or just it’s maybe a calculation?

Well, I’ll just answer the Woodside point and then you can comment to the other points, Richard. From our perspective, there is no issue Woodside as a partner.

We’re working extremely well with them. We think they are great value-adding partner.

As I said, we have established good relationship. One of our partners has a dispute with an outgoing partner and I'm not sure where that's got to.

But yes, from our perspective - from the government's perspective, Woodside adding value and it's moving forward and there is no delays as a result of that.

So couple of points - I'll pass on to Paul for some of it - but I think on the numbers, the 473 million is ERC’s number, is one thing that's what they independently assess that. That is just the oil portion.

The numbers that we've been quoting they are ours, so they will be slightly different, although very close, but then also the BOEs that were quite involved with the associate gas as well, so that's why there will be some difference there. In terms of the VR-1 well, I think the - it’s the lower reservoirs that are the easy part of the field to develop because we are very confident that they will be the most valuable oil because we expect less wells to be able to extract a greater proportion of oil because they are water-floodable.

That's really why that is an important element to secure and that's why this well is an important well to drill at this point, because the first phase of development will likely be aimed at the easiest and most valuable oil.

Yes, so just building on - as obviously there is number of plan I touched, not just technical that we consider in terms of looking at most optimal development and obviously bringing up the 1C number has a number of advantages. But we shouldn't dismiss that VR-1 is targeting this carbonate play which is riskier in terms of exploration risking but it’s the oilfield potentially under the oilfield.

And so before we put subsea infrastructure in place which just now is targeting the upper and clastic reservoirs which obviously extend over a large area, we really need to know is there anything worth pursuing below it before we put subsea templates for example and a number of slots and so forth. So is that a necessarily extending the field and on a real sense we need to know does it extend vertically, in this case, downwards.

So it's quite an important way in that regard from the development planning and that's one of the reasons we were quite keen to put it in the slot now and then we'll go back to do SNE-6.

Hello. Elaine Reynolds from Edison.

I'd like to ask a question about SNE, the upper zone. You've seen much better deliverability from the SNE-3 and 5 wells but a lower rate in the 2 well.

Can you talk about the distribution of those sands to the North and South of the field since SNE-2 is in the North, and what the split you see between the upper and the lower zones in terms of resources? And also I'd like to ask another question about the Porcupine basin.

Is the $30 million that you're intending in this year for Druid and Drombeg, is that equate to the 30% working interest, or is it an additional amount? And now that you're going to be drilling Druid and Drombeg, how does that impact on your plans for Spanish Point?

I’ll try and take Senegal first. Yes, we've now drilled seven wells in the SNE field and effectively - it's every time that we've drilled it, we've been able to see the same reservoirs effectively.

We've collected a large amount of data. And we've got multiple reservoir layers in there.

We have very simply divided them into two fundamentally different ones which we've seen every time, the lower ones which we are starting to call as, the 500 series, and the upper ones, the 400 series. The proportion of oil in place just because the shape of the field is more in the upper reservoirs, and therefore the key for us having seen the different flow rates in SNE-2, that did a test of the lower reservoirs that flow to 8,000 barrels a day, so that was clean excellent test.

It was a very small interval we tested then in the upper reservoirs. It was just a few meters.

And of course it flowed but it was - literally from one or two meters of reservoir. At that time of course that was the first test we had conducted.

When went to SNE-3, we deliberately aimed at the upper reservoirs and we conducted a couple of tests there. High flow rates and sand quality is good.

In fact the sand quality we see right across the field, including as you go north to the Bellatrix, which is the most northerly appraisal well, sand quality isn't really an issue. We can see connectivity in terms of correlation from well to well but individual sand bodies, that's the issue that we are trying to address with this interference test.

We have very high quality seismic data and we can see the different shapes of sands, running in two directions really as I've pointed out on the slide there and it's trying to understand what those features that we can identify on the seismic data, what do they relate to in terms of the way that the oil and fluids will move when we start to develop the field. Will they move in a preferential direction?

And in each reservoir layer, because we can see multiple layers, the patterns are different in each layer. So we have to understand that.

Now we cored many of those wells last year. We got over 600 meters of core all the way through this reservoir from pretty much across the field.

It's a huge database to integrate all that data at various different scales, including this latest interference test data that we will pick up from 5 and 6. So at the moment, we haven't given a specific figure as to what proportion is going to be developed from each reservoir.

That will be something that comes out following this latest round of appraisal as we build our reservoir models specifically for the development plan for the first phase of development. And at that point, we may be able to say more about what the proportions might be.

Paul, do you just want to touch on the Spanish Point?

Yes, Spanish Point, we were still in the license and I think the cost question was really - it’s not the well cost - and I don’t know if James wants to add to this - but it’s obviously the bank cost. The well cost including our promote [ph] and the level of contingency.

Yes, the deal was effectively a three for two carry subject to a cap on the overall well cost. So it's a bit more complicated there but simplistically we are paying 45% of the well cost for the 30% interest.

Okay. Couple of more questions and then we'll probably need to wrap up.

It’s Sanjeev Bahl at Edison. Just two questions please.

Firstly on FlowStream. The implied cost of capital of that facility, I guess, is well in excess of 10%.

So I was just trying to find out, was there an option to extend the RBL to cover the additional 4.5% of CapEx for the first oil stake, or whether there are other sources of finance available that seems relatively high compared to the other facilities you have in your debt portfolio? And the second question was really on cost guidance for Senegal.

I think in the past you've mentioned $10 a barrel life of field OpEx, which still seems relatively low compared to similar size analogs, maybe Catcher and Kraken are on the smaller size. But just trying to understand whether your thoughts on OpEx have changed at all, or whether FPSO leased rates are just exceptionally low at the moment?

Why doesn’t Paul do the OpEx?

Just on that, obviously the FPSO leased rate which will dominate the OpEx profile has big bearing[ph] on what size of FPSO we are building, which is still under discussions. So I think we've actually guided in the past with a range which was obviously what I prefer at this stage whilst we are as basically still determining what is going to be the scale of the project.

And obviously the other thing, which is the length of the period to the length of the term of the FPSO lease, clearly now also have a bearing on the absolute value of the lease. So those are the key parameters and that's what we are in the process of trying to determine.

James?

Just to add on that briefly before I could go on to your question about the FlowStream deal - the guidance we gave, $10 a barrel, was for all-in OpEx at plateau rate of 120,000 barrels a day as an indicator. So life of field, I guess, it might be a little bit higher than that.

And of course, as Paul said, you may well structure at least with the purchase option and it will depend on the term and so on. So it's guidance for a plateau rate at those levels that we gave six months ago.

On FlowStream, yes, the RBL effectively has structured to include assets that - sanction development assets that we have or that we acquired, so of course the 4.5% would automatically rolled into that. I guess the cost of capital is relative to the risk that they are taking.

So FlowStream is taking full field and price risk in terms of the return, I guess for that, so we have designed it around at 10% return stepping - that then automatically steps - significantly steps down that royalty and effectively caps it out with a further step-down but we felt that that was a reasonable return relative to the effectively project equity risk that they are taking, and that it was a neat way to ring-fence refinancing to assets - an interested in an asset that we acquired during the course of last year and also it was useful to diversify our financing base.

Okay.

Hi, it’s Alwyn Thomas here from Exane BNP Paribas. Just quick question on M&A.

Your name has been mentioned in connection with a few asset deals in the North Sea or assets for sale. Can you give an update on where you might be looking for and how you intend to fund the sorts of deals?

Yes. We’re looking for value, not volume, number one.

So that maybe rolls out a number of things that you might read about us. We are more interested in particular in assets and really at the end of the day, as you’ve seen, we are comfortable with the balance that we have at the minute in terms of the portfolio of the balance of - balance sheet strength, production from Catcher and Kraken and then a stream of exploration activity.

Obviously if there is opportunity to enhance that on either side, and you see in Ireland there is an example on the exploration side but also on the production side, then we’ll look at that. But we would look at that from the perspective one what is the value of those barrels.

Do they pass our strict investment criteria, and two, what we want to avoid is falling into a try for being over-geared for acquisitions and so on. We are not interested in doing that.

Any other questions? If there aren’t, just one thing before we finish.

This will be the last year that Richard will be sitting in front of you. And whilst I'm delighted with Eric Hathon, who will be replacing him, very sad to be seeing Richard go.

I've been working with him for over 20 years and he has been nothing but a joy to work with and a great value adder for Cairn. So please could you join me and show your appreciation for him.

Thanks so much.