Capricorn Energy PLC

Good morning everybody. Welcome to Cairn’s Half-Yearly Results presentation.

I’m Simon Thomson, Chief Executive. With me are James Smith, CFO; Richard Heaton, Exploration Director; and Paul Mayland, COO.

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

Cairn’s strategy is to deliver value for shareholders from a balanced E&P portfolio. To do that, we seek to create significant growth opportunities within a portfolio that is both sustainable and self-funding.

Within that portfolio, we have got exposure to material discoveries and prospectivity principally in Africa and North West Europe, and those interests are held at appropriate equity levels for the size and scale of company that we are. Our UK developments are progressing on-track and under budget, and will deliver significant production for us from 2017 onwards.

And as you will have seen from today’s announcement, we have established a substantial and growing resource base. It’s worth noting that our net combined 2C and 2P resources now total in excess of 0.25 billion barrels of oil equivalent.

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

We have commitment to continued delivery of value from discovery and development, including potential further returns to shareholders, and that’s in line with a consistent strategy of creating, adding and ultimately realizing value for shareholders through monetization. So a few words on Senegal where a safe and successful appraisal drilling campaign has confirmed the world class nature of the SNE field.

Paul and Richard will come on and talk about the detail, but in summary, we are delighted with what we have proven up thus far, and also with the additional potential that we see, not only in SNE, but also in the surrounding acreage position. The resource base continues to increase, and today we have announced a significant upgrade in our contingent resource estimates.

The SNE 2C STOIIP is in excess of 2.7 billion barrels, and that’s with current gross recoverable resources now standing and revised to at the 1C level 274 million barrels, at the 2C 473, and at the 3C in excess of 900 million barrels. For the sake of comparison at the 2C, as you know the previous guidance was 385 million barrels, so a significant increase.

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

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

The third phase of E&A drilling is scheduled to commence at the turn of the year, and again we are benefitting significantly from reduced costs both in respect of rig and also associated services. So in summary, we see continued delivery of value from Senegal.

The combination of reduced costs, increased resources, and also near-term activity that will access in our eyes significant potential upside. So there is a lot still to go in Senegal.

James.

Thank you, Simon. Good morning everyone.

So in the next few slides I will go through the cash flows for the first half, the current funding position, and an update on our future capital investment plans. As you will see, the focus remains very much on capital discipline to continue to ensure that we retain the flexibility to direct investment to the assets where they will deliver the best returns.

For us today, that’s really about two key areas. The first is completion of the Catcher and Kraken projects to deliver sustainable cash flow from next year, and those barrels are with an all-in average production cost of $17 a barrel at plateau.

The second, which we will spend most of our time today talking about, is further de-risking of Senegal, and that’s really an asset that’s delivering on our principle strategic goal as a company which is about material, low cost resource bases within large acreage positions. Beyond that, investment plans are really about earlier stage exploration activity across the rest of the portfolio, and continuing to assess the opportunities to enter into low cost new business development opportunities.

So this slide just takes you through the first half cash flows. As you can see, $603 million was the opening cash position.

Principal expenditure during the period was on the full well Senegal appraisal and exploration program, and on the Kraken development project. During the first half, and actually as of today, we continue to be fully carried with respect of the Catcher project, so that’s why there are no cash outflows there.

So all of that together with relatively low activity across the rest of the portfolio, or low capital investment across the rest of the portfolio I should say, and a continuing low G&A expenditure, with debt remaining undrawn, that took us to a cash position at 30 June of $414 million. So taking that forward, the next slide sets out the current sources of capital available to the Group over this year and the next year on the left hand side.

And on the right side the expected or committed and planned uses of that capital again over the period between now and the end of 2017, which will deliver us into free cash flow in the North Sea. So starting on the left, $414 million opening cash position.

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

Clearly next year we will also be moving into operating cash flow phase in the North Sea, first of all-in Kraken, and towards the end of the year we expect on Catcher. There is some guidance there in the box of what we would expect operating cash flow to be from Kraken, ramping up in the second quarter of next year towards peak.

Even at $45 oil representing the forward curve, that would be round about $100m of operating cash flow next year. So all of that together is about $800 million or so of existing funding available to the Group between now and the end of next year.

If we look at beyond that in terms of the operating cash flow. As I said, oil and production costs for Catcher and Kraken of $17 a barrel, significant tax shelter, means that even at today’s oil price in the mid-40s we will be generating around about $250 million of operating cash flow at plateau production, or at $65 in oil Brent for illustration, about $400 million of operating cash flow.

On the right hand side, you can see, starting with the committed uses of CapEx, and moving into what we plan further in Senegal. $45 million of working capital, effectively activity undertaken in the first half where cash flow out has been post-30 June.

$315 million represents the total development CapEx for Catcher and Kraken net of the carries in favor of Cairn between now and the end of 2017, and you can see there the split between the two assets and the phasing between this year and next. Committed as of today exploration and appraisal activity, $55 million, which represents ongoing activity in Senegal, plus relatively low commitments across the rest of the portfolio.

And in the next two blocks there represent what we see as being still under currently planning phase, but the expected minimum activity in Senegal in 2017. So that’s two appraisal wells with one or both of them having a relatively full testing program, and pre-development study work ongoing on the assets, so that totaling around about $80 million.

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

Last point on funding. None of these plans includes a resolution of the ongoing dispute in India with regard to the retrospective tax application to our internal reorganization in 2006.

That was a $1bn asset that was taken away from us in 2014 for which we are seeking full compensation through the international arbitration process. That process is now well underway.

We submitted our full statement of claim to the Arbitration Panel earlier this year, and the Arbitration Panel has asked India to respond in full before the end of this year. So on that basis we would expect to move to hearings in the first half of 2017, and a ruling thereafter.

So as I said, none of that included here, but clearly we are expecting a positive outcome on that. Next two slides provide an update on the two UK development projects, and really it’s a similar story in some ways across both of them, development drilling running ahead of schedule, subsea installation in the North Sea completed on Kraken, and expected to complete by year end on Catcher.

For both of them the critical path item to getting to first oil is really around FPSO construction, and you can see here the Kraken vessel in Singapore with all of the modules now lifted on and sail away expected in Q4 of this year. On Catcher, you will recall we guided the market that there had been a bottleneck in the hull construction in the yard in Japan.

The mitigation plan which the partnership has put in place to address that has now been affected, and you can see here the complete hull/vessel joined together in Singapore awaiting the modules to be lifted on top, and that keeps us on-track for expected first oil in 2017. The story across both of those development projects, as well as across the rest of the portfolio, has been one of benefitting from the flipside of the lower oil price environment, which is an improved cost and contracting environment.

You can see here we have been very active in managing our capital program and our project costs over the last 12-months. Starting on the left hand side, the first two points together, we have deferred about $80 million of previous exploration commitments where they didn’t make sense as investments in the current oil price environment.

Where we have been exploring here in the UK and Norway, that activity has come in around $40 million below the original budget. There isn’t a block on this chart here for it, but it’s also worth remembering that in the first half of this year we undertook a four well appraisal program in Senegal for the same cost as has originally been budgeted for three wells.

Then here, you can see the most significant blocks on this chart in terms of CapEx savings were across the two development projects. So together across Catcher and Kraken net to Cairn savings between now and the end of 2017 are about $160 million, and we continue to work on initiatives with the operators of those projects so expect more to come.

So all of that net of having taken on more equity in the Kraken project, means that we have deferred or reduced $226 million of CapEx to the end of 2017 over the last 12-months. Onto the asset where we are expecting to have the optionality to deliver the most value from the current cost environment, and that’s in Senegal.

This slide provides an update on the development scenario and associated costs for an SNE 2C development. It’s a chart in the same format that you will find back in our Capital Markets Day in May 2015, but with some important revisions to that.

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

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

Operating costs associated with that development scenario, $8-10 a barrel, and that includes an FPSO leased cost assumption in there. And again on timing, the guidance remains the same.

So with the development recommendation in 2018 and FID in 2019, we would expect first oil to be in the window 2021, 2023. Next slide here sets out of the economic outputs of that development scenario if you like, with NPVs per barrel at the various oil prices, and unlevered project IRRs at those same oil prices.

You can see there with the dotted yellow lines, which represent the guidance we gave back in May 2015, that that results in a pretty significant upgrade both in terms of value and project returns from the previous guidance. And as you can see, pretty healthy returns even at today’s oil prices and we think reaching a threshold 10% return in the low 30s Brent.

Clearly these are economics for the 2C standalone development of an SNE field scenario, but as Richard will come on to talk about, the significant resource upside potential in the block, so exploration success near to that field could clearly be developed at relatively low cost as a tieback to the central development. Finally on SNE economics, this slide here sets out the results of that development plan in the context of breakeven oil prices for other projects globally.

It’s taken from the Goldman Sachs study of international upstream projects, which we have screened for development phase projects, and you can see SNE ranks extremely highly on that list in terms of its ability to attract industry capital. And as Paul will come on to outline in a bit more detail, whilst SNE is normally a deep water development, the operating environment, the geological characteristics and the fiscal terms altogether combine to mean that it actually ranks above many shallow water or shallower water development projects and even some onshore ones in terms of its economic attractiveness.

So in summary, before I hand over to Richard to talk in some more detail, the focus has been very much on capital discipline to make sure that we have an investment strategy that’s very, very focused on assets to deliver returns in a lower oil price environment. And as a result of that we are very well positioned to deliver the business into cash flow phase next year and to support from the current balance sheet our continued investment in the Senegal asset, whilst in the background continuing to build the portfolio opportunity set in the background.

And on that note I will hand over to Richard.

Thanks, James, and good morning everyone. First of all, just a brief reminder of Senegal.

Two years ago we still hadn’t made our discoveries in Senegal so we have made a tremendous amount of progress since then; six wells now drilled. And you will see that essentially the first two wells both were discoveries, they were both the first wells ever drilled in the deep water offshore Senegal and the first two oil discoveries of any size in Senegal as well.

We have focused our attention since nearly wholly on the SNE area, it’s shallower water, the reservoirs are better quality there, and that is really where the bulk of our effort has been to date. What is new today is that we are announcing an upgrade in the resources that we see in that field and also giving the detailed figures out on very large in-place oil that there is in the field.

We have a very large area in the license and I will be talking about the exploration potential there as well. So the next slide really talks about the results of those wells that we have now drilled.

We have had a very successful and safe campaign to appraise the SNE field, we now have five penetrations across that field, roughly sort of nine kilometers in a north south line and about five kilometers from east to west, right in the central portion of the field. The field during that time, as we have proven with these wells now, has increased in size and at the very top seal the area of the field is over 350 square kilometers.

We have across that area now, so far as we can see there is a very consistent 100 meter gross oil column there with a gas cap above it in the centre of the field. We can see that everywhere we drill those five wells we have good quality reservoirs and better than perhaps one would normally predict in these age of rocks and type of rocks, but it’s very consistent, and shown on here, just one of the reservoir layers in the upper levels of the reservoir.

Right across the field we always find sands, we always find them of good quality, we can actually tie them very accurately on the seismic data, we have new seismic data and we process seismic data now that ties very well across the field. And we can use the amplitudes from the seismic data as shown on that little map to almost differentiate between where there is gas, where there is oil and water, and some of the internal features of the rocks there.

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

It’s a fabulous database to work with and we are still working through it. What that means is we are able to confirm a great deal more certainty now about the field, we have got great information that allows us to understand how it’s put together.

And essentially as we said and saw in SNE-1 the reservoirs are best at the bottom and then we have lower reservoirs above that, the finer grained and slightly thinner reservoirs above that. We have got good test results out of both though, the lower reservoirs, 8,000 barrels a day out of one test and in the upper reservoirs 5,000 barrels a day.

Those are great test results for anywhere, some of the better ones that you will see along the West African margin. In the test that flowed 5,000 barrels a day from the upper reservoirs, some slight pressure depletion which shows that the connectivity there is not quite as good as in the lower reservoirs, and that will be a feature of trying to understand that uncertainty when we come to the next phase of appraisal.

So the resource base is hugely improving as we go through, for the first time here giving the figures on where we were at March with the associated in-place oil, the STOIIP, and today’s estimates are independent estimates given by ERC-Equipoise, demonstrating if you like the consistency between our own and an independent auditor’s view. And we have now got over 2.7 billion barrels in place at the 2C level and a recoverable resource out of that of 473.

And you can see it’s a wide range, these are probalistic estimates, this is trying to take into account still the very large variation there is in the field, because we are still really at the relatively early stages, only 18-months after discovery, of trying to piece together what is now a very large field. But it’s a great story, what we will be doing with the next wells is trying to understand better the connectivity and make a yet more informed decision about how best to develop the field and what sort of field development plans put in place, and Paul will go on to explain some more of that.

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

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

So the Sirius Prospect we have talked about before. This is on the shelf, it’s just to the north of SNE, it’s at the same reservoir levels, we can separate it out at some of the upper reservoirs here within SNE, we see this as relatively low risk, it’s a stacked field as we now know from SNE is the case.

Probably around 80 million barrels, just over 80 million barrels when you consolidate those in the prospect, but a very high chance of success based on what we see in SNE, so a 67% chance of success. This could be a very attractive tie-in prospect.

And if we go to the basin you can see the FAN well in there to the north, that FAN, a very large column of oil, over 500 meters altogether of oil soaked rock, but the reservoir quality in there, it’s quite deeply buried, not so good. Further to the south, there is a prospect here that we are looking at which is much shallower, we can see the feeder sandstones coming in from the shelf, from the field, SNE field, we do hope that the reservoir quality here might be better.

In just one layer in this prospect we have about 150 million barrels mean prospect resource in here with about a 15% chance of success. It is a stratigraphic prospect, stratigraphic trap, that does work at FAN, it could well work here, again it would make a very attractive tie-in.

Now all this work is still very much ongoing, integrating all the new data from SNE and the new seismic, we haven’t made decisions firmly yet on which wells we will be drilling as part of an exploration program, that is still yet to come. And at this point I will pass on to Paul to take us through the next stages of the operations.

Thanks, Richard. Good morning ladies and gentlemen.

As already mentioned, we intend to move to a third phase of drilling offshore Senegal, commencing towards the end of this year, and we aim to build and indeed improve upon the good HSSE performance that we achieved during 2015 and 2016. The proposed program is anchored around two firm wells, plus multiple one well options and both semisubmersibles and drill ships are under evaluation for what has already proven to be a very sought after contract.

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

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

Further appraisal activity is focused on improving the definition of the project, in particular related to water flood planning of the upper reservoirs which ultimately influences the number of drill centers and their location and the number, location, offset and orientation of production and injection wells to be drilled on the field. The concept that we have previously outlined, a floating production, storage and offloading vessel with subsea wells remains valid and the 2C resources presented today guides us now to a plateau rate of between 100,000 and 120,000 barrels of oil per day.

I think everyone is familiar from the capital markets day of last year with the timeline shown at the bottom of the page, I think that illustrates the remarkable progress the joint venture has made in only 18-months since discovery and the considerable effort that we will undertake together over the next 18 to 24 months to allow us to submit an exploitation plan in the first half of 2018. On this slide you can see a diagram which outlines a range of offshore projects versus water depth taking us all the way out on the right hand side to the current technology limit for deep water of around 3,000 meters.

SNE obviously sits very comfortably within this window and is classified as a deep water discovery being located in approximately 1,000 to 1,200 meters of water. Indeed, it is worth noting that the SNE reservoir depths are actually less than the water depth alone in other global ultra-deep water discoveries in the Gulf of Mexico and indeed, close by in Africa.

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

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

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

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

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

A variety of well types are being investigated but most are ultimately of a near horizontal or high angle type with lateral sections of around 1500 meters in the reservoir and may or may not include some form of intelligent completion. On average we believe that the well costs have reduced by around 25% from our previous estimates and this has been carried forward in the economics presented by James earlier.

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

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

Thank you, Paul. As Simon pointed out in his introduction we have a balanced portfolio and as well as the Senegal story we have an interesting and building portfolio in the UK and Norway.

Of course we have talked about the two development projects but our exploration plans in the UK tend to be centered around those fields; and if we go to Norway where we have the Skarfjell discovery in 2012, we have a focused exploration portfolio around that area too where our expertise can be honed. And we also have a building position in some of the less well explored parts of the Norwegian Sea and Barents Sea where we share the NPD’s view that with just 100 wells drilled today there is a considerable yet to find potential in that basin.

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

Beyond that of course we have to continue to look at new ventures. The current market state means that it’s probably a good time for an acreage reload and refresh the portfolio but we are looking for those options where we can get in at relatively low cost.

We see those, there are quite a number of them at the moment, and we are very focused on making sure that we access the best of them, focusing first of all along the Atlantic margin where we do have some technical expertise and knowledge. But it’s a great time to be trying to do this and we hope to bring some new news over the coming years on this.

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

Thanks, Richard. So in summary we continue to offer significant growth opportunities within a balanced portfolio.

We have got a material and growing resource base in Senegal as you’ve seen and we have got further near-term drilling activity to access upside resource and are benefiting from a lower cost environment. We have got balance sheet strength and we have got substantial cash flow from near-term production from Kraken and Catcher in 2017.

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