Capricorn Energy PLC

Okay. Good morning, everybody.

Welcome to Cairn's Results Presentation. I'm Simon Thomson, Chief Executive.

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

It's being webcast, so there will be microphones available, if you do have a question. Turning to the 1st Slide.

Cairn's strategy is to create at and realized value for shareholders. These last few years have seen the company rebuilt.

We're now for a fully funded, full cycle sustainable portfolio with an active development pipeline and a multi-year material exploration drilling program. And for that exploration we continue to focus on gaining large acreage positions with follow-on potential and attractive fiscal environment and appropriate level of equity risk, so we're always looking at that balance of cost, equity and reward.

If you look at the bottom left of the slide in terms of our portfolio and just running through the various steps. First of all in terms of identification, we're constantly seeking to identify new opportunities to bring into the portfolio so the two Blocks in Mexico last year were an example of that Suriname which we announced today.

We've a very active team and I expect that we will bring in other opportunities into the portfolio during the course of this year and may lead to the next step exploration. As you know we've got an active program in the UK, Norway over the next couple of years targeting about a 1 billion barrels gross of unrisked resources and in fact we're currently operating two of those wells.

And in Mexico next year a lot of activity ongoing there to plan for four wells over 2019 and 2020 and again that's targeting over 1 billion barrel gross across those two Blocks in terms of unrisked resource potential. Where we do have success in exploration we quickly move to appraisal.

So last year saw the successfully and safely completed third phase of Senegal drilling so that field is now fully appraised. And that leads us to development and obviously we're talking about this today we have two developments moving forward to FID, one is Nova formerly Skarfjell and the other is the SNE development in Senegal and as you will know both of those being generated from exploration discoveries within the Cairn portfolio.

And those were both sustained and potentially enhanced to current equity levels production. So we will talk today about Kraken and Catcher production 25,000 barrels a day net to us mid-year on plateau and as I say, the developments within the pipeline will sustain and enhance that plateau and that production provides us the cash flow in terms of the ability, the final step there to be able to not only reinvest in the portfolio in both sides in the ongoing exploration activity and maintenance of that production profile, but also potentially a target of our choosing to monetize and potentially enact further returns to shareholders.

Now all of that is carried out against the backdrop of continued capital discipline and prudent balance sheet management. And on that subject I'll hand over to James.

Thank you Simon and good morning, everyone. So on the next few slides I'll take you through an update on the current financial position as well as guidance for 2018, that will take a financial overview of the two development projects that Simon mentioned Nova and SNE which Paul will then go onto to expand on and then finally we'll take a look at the longer term cash flow shape of the business.

so on the Slide 5 here, you can see with regard to the funding position at year end, the cash on the balance sheet $86 million, a Norwegian tax receivable in respect of 2017 exploration activity in Norway of $38 million and the debt facilities, the RBL facility for the North Sea remained undrawn with availability at year end of around about $200 million. Looking forward to the capital program and cash flows for 2018, you can see development expenditure expected $140 million across Catcher and Kraken and I'll come onto some more detail on that in a moment.

Currently committed exploration appraisal spend of $95 million and that reserve base lending facility mentioned undrawn at year end, we expect the capacity under that to increase during the year as Catcher and Kraken go through the final stages of commissioning and to peak at around $400 million later in the year. Production guidance for the year, net to Cairn as we've already guided 17,000 to 20,000 barrels a day with OpEx of $18 a barrel on average across the two fields, net to us.

Around about 30% of that expected production for the year is hedged with a floor price of $58.40 effectively to enhance debt capacity and underpin the committed forward capital program. As ever the business plan is fully funded without the value or in the absence of the value of our investments in India, our billion dollars of investments there are frozen by the tax department and that domestic dispute continues and due to the tax department has been pursuing enforcement action in 2017 against income due to us.

But ultimately the resolution of that dispute is going to be via the Sovereign Treat Arbitration process which as you know is now well advanced final submissions are due shortly and the hearings will be in the second half of August with an award thereafter probably in Q4, 2018. And as a reminder, our claim under that treaty process is for $1.3 billion effectively the value taken from us in 2014, when the shares were frozen and other income that's been seized since on the basis that has breached the protections available to us under the Investment Treaty between the UK and India.

So looking back now the cash flows in 2017, the opening cash position $335 million. Financing cash flows in during the year principally the completion of the FlowStream royalty financing on the additional equity we acquired in Kraken in the prior year $75 million.

And you can see the first capital items across UK and Norway, $60 million spent that was the Tethys well which is ongoing, planning for this year's multi-well program in Norway and UK and seismic processing, that $60 million should be considered net of the $29 million drawing on the exploration financing facility, so effectively net of tax rebate that's $31 million spend in the UK and Norway. In Senegal $103 million that delivered the five well appraisal exploration program for the original budget intended for four well, so expanded that program and delivered it well under budget as we've previously announced.

In the international region, $67 million there that's principally the Druid/Drombeg well in Ireland and Mexico entry cost and seismic purchase cost associated with that entry into Mexico and other seismic cost across the portfolio. And then finally the development spend during the year $146 million that was split $98 million on Kraken, $48 million on Catcher.

So if we take that with the admin charge for the year and the operating cash flow which is disclosed in today's preliminary results announcement the first cargo sale on Kraken, the settlement of our Mongolian royalty income net of OpEx for the year, with the tax rebate due from 2016 activity in Norway of $30 million takes you to our yearend cash closing position of $86 million. Looking forward now to the capital program for 2018, you can see here the split out of that expected $140 million on Catcher and Kraken remaining development spent.

Catcher that is for the ongoing development drilling during the year as well as first oil payment to the FPSO owner when first oil was reached in paid in January. On Kraken that $70 million will be for the ongoing DC 4 drilling and subsea installation and also includes a $15 million carryover from 2017 activity, cash outflow in respect to 2017 activity.

And those development cost don't yet include what we expect to be the beginning of Nova expenditure which I'll come on to talk to about in a minute, sanctioned for that in the coming months. So the remaining items there, Senegal pre-development spend $35 million across the international portfolio including pre-drill exploration costs in Mexico and the close out cost for the relinquishment of our acreage in Western Sahara and then finally, $35 million net of tax rebate that guidance is provided for the Norwegian and UK drilling program expected four wells this year and some seismic cost associated with that.

So that's total capital expenditure for this year currently committed of $235 million. So looking now at a financial update on the SNE project, as we've previously said we're targeting approval by the government of an exploitation plan covering the full half a billion barrel resource base in SNE, this year.

Phase one of that development plan will be targeting principally the deeper S500 reservoir sands, 240 million barrels with target peak production of 100,000 barrels a day. We're reiterating today our CapEx guidance for the project across all phases of $12 a barrel.

Phase one will obviously be slightly more waited towards subsea and production facilities and subsequent phases more waited towards drilling expenditure. But in aggregate around about 60% of that total development cost will be well related.

So that translates into CapEx prior to first oil, net to can of about $800 million with first oil expected in the period 2021, 2023 and we've already begun work on the project financing of that capital spend. As you know, it's going to be an FPSO development, we assume for these economics that there will be a least FPSO and as we've announced it's relatively likely that maybe a redeployment of an existing FPSO vessel.

So that leads to all in OpEx including the FPSO least in the range of $10 to $14 a barrel without range predominantly depending on the vessel candidate used for the development. So we take all of those inputs together with the attractive PSE structure, if you recall it's a 75% capital on cost recovery and the government participation directly in the project between 10% and 18% through Petrosen and in profit oil through the PSE terms at around 20% expected for the production levels that we have, all of that gives very robust economics even at $50 as you can see on the slide here we calculate that the IRR 10 breakeven of the projects at FID within the mid-30s Brent.

So moving now to look at Nova formerly called Skarfjell which is up for sanctioned by the joint venture in the coming months, this is an 80 million barrel oil equivalent field in which we participate 20% discovered in 2012 following our acquisition of assets in Norway. It's going to be developed as a subsea tie-back to the nearby Gjøa field and as such development cost of around about $15 a barrel over the life of the development which translates into net CapEx to Cairn of approximately $200 million.

As a tie-back it's relatively low OpEx production $7 a barrel at peak production and so all of that again delivers robust economics you can see there, project IRRs unlevered at $50, $60 and $70 Brent. It also is a project that fits very well into the cash flow profile of Cairn which we'll look at on the next slide.

So as I said looking out now over the slightly longer term through to SNE coming on stream. You can see production growth from this year into next as we have Catcher and Kraken coming fully on stream for a full year in 2019 and thereafter Nova coming on stream in 2021 which sustains that North Sea production base.

As I mentioned development costs net to Cairn prior to that Nova production coming on stream of about $200 million and we expect to be able to draw substantially on the existing RBL facility in order to support that development expenditure. So that gives us a position from the North Sea where we're generating $60 Brent sustainably about $350 million of operating cash flow through to the period where SNE comes on stream and that's a very solid funding base in order to deliver those development.

We've SNE coming on stream there clearly a very transformational event for the portfolio whether that's from the production uplift with us continuing Cairn [ph] participating interest or whether it's the opportunity to monetize part of that interest during the development process. But working on existing participating interest as I mentioned that's net CapEx to Cairn of about $800 million, we've already begun work with the joint venture and the government on project financing for that, so on the basis that we will be able to leverage about 50% of that expenditure for debt funding that CapEx is clearly something that can be easily sustained out of the North Sea cash flow.

That said, of course we always actively consider portfolio management across the asset base in order to optimize our capital allocation, but the important thing is, that we have funding flexibility to be able to make the choice to do that at the optimal point for the portfolio. And on that note, I'll hand over to Paul to talk about the projects in more operational detail.

Thanks James. Good morning ladies and gentlemen.

2017 was a very successful year for Cairn in terms of delivering a number of operational development and production milestones. Our operated drilling projects were successfully executed without loss time injuries and included the six wells in deep water offshore Senegal.

We also actively participated as a partner in the deepest water exploration well ever drilled in Atlantic Ireland. Wintershall as operator completed front end engineering and design studies on the Nova field and both of our UK, North Sea projects came on stream just over three years following final investment decisions.

2018 also contains a number of significant planned milestones for the company. In Senegal, we plan to prepare and submit the evaluation report formally documenting the end of appraisal in the first half of this year and then the exploitation plan shortly thereafter which is a full life of field development plan targeting a plateau rate of 100,000 barrels of oil a day.

We aim to commence and progress through front end engineering and design with key contractors for our SNE phase one and Senegal. The plan of development and operation of the PDO for the Nova field will be submitted to the authorities in the first half of this year and a final investment decision on that project taken by the joint venture partners thereafter.

And on both fields in the UK, North Sea we're anticipating continuing to optimize the production performance. The operator EnQuest on Kraken are already producing steadily between 40,000 and 50,000 barrels a day.

And on Catcher premier plan to complete FPSO commissioning to allow us to raise from our current levels of up to 30,000 barrels a day to the target plateau of 60,000 barrels a day. The SNE project in Senegal remains on track with the schedule we first outlined to the government and investors following the discoveries in late 2014.

Three years later we've successfully concluded appraisal and completed the concept select stage and this was established following integration of the final appraisal well data and the Net Ocean environmental and geotechnical data gathered in the last year. The environmental and social impact assessment associated with the project which outlines the benefits of the project may bring and how the project risks will be successfully managed is targeted for submission before the summer and the exploitation or field development plan as I already said will follow in the autumn.

This plan will see SNE developed in several stages allowing for oil and potentially gas seals. An initial phase focused on the lower better quality reservoirs by including an important component of the more extensive upper reservoirs which contains approximately two-thirds of the overall 2C resource.

A further phase which extends the subsea production system and adds further development of the upper reservoirs and a third phase, seeking to maximize economic recovery of oil and gas from the field where there is a total deterministic resource potential of approximately 500 million barrels on 1 TCF of gas. And this overall plan would be very typical of West African development indeed such as Baobab or Jubilee.

We're targeting approval by the end of 2018, at which time we expect to have progressed feed with the preferred contractors. The diagram on the right illustrates the preferred concept of two initial subsea production floor loops one north and one south of an existing submarine canyon feature connecting subsea wells via turret moved FPSO on the eastern part of the field in approximately 800 meters of water.

Tenders for the FPSO and for the subsea production system and the subsea umbilicals, flowlines and risers have been issued to the contract community. We expect a lot of interest in this project and Woodside have already completed on the joint ventures behalf of very comprehensive engagement process such as the project is very well understood and we believe, we'll be competitively bet for recognizing it will be the first offshore oil project in Senegal.

This project like any others has some unique features but overall benchmarks well with other West African oil projects. Following extensive reservoir modeling in 2017, recoveries per well as shown in diagram on the left are consistent with typical range for relatively shallow reservoirs developed under water flood with low viscosity oil.

And the light sweet nature of the crude positions it well for local African and international markets and should attract strong pricing. We move onto Norway.

Operator Wintershall has optimized the Nova project and have incorporated their experience from their similar Maria [ph] project which was also a subsea tie-back. The PDO is prepared and is anticipated to be submitted in the second quarter this year to the NPD for a project that will deliver 50,000 barrels of oil a day on plateau and develop gross reserves of 18 million barrels of oil equivalent.

The Nova fluids will be processed on the Gjoa host platform which will involve a single module installed on an existing slot. Development drilling will commence in 2020 and first oil is expected in the second half of 2021.

On Kraken, we've much improved production uptime and are now consistently producing between 40,000 and 50,000 barrels a day when all 11 existing producers and 10 injectors are online through the process trains. Uptime for both production and injections systems in January and February was particularly good and it was only the extreme recent weather that we saw right across the UK that disrupted this performance and resulted in the shutdown.

And a joint venture has now taken the opportunity during the shutdown to bring forward as much and much as possible of the operators previously announced process improvement work, which was previously scheduled for April and May. The objective for 2018 is to continue this good performance and to optimize production and injection across the field allowing for this process improvements and then in the second half of 2018 to complete the subsea scope for drill center four and drill and complete the remaining four plan development wells.

Two producers and two injectors and a central core part of the field. The full cycle CapEx is down 25% from final investment decision and with regular liftings now established, strong interest is been showed in the crude from European, US and Asian buyers.

And last but by no means least, all of the joint venture we're delighted achieve first oil from Catcher just before Christmas last year. The plan in 2018 will be to complete the commissioning of the FPSO and to ramp up to the production target levels of $60,000 barrels a day during and before the summer.

Full cycle CapEx is down 30% from the final investment decision and 14 of the planned initial 18 development wells are now complete. Reserves have been upgrades slightly and strong interest is been showed in this medium API crude with a currently trading and a small premium to Brent and looking out further on Catcher, the joint venture is evaluating possible development of satellite discoveries in the vicinity of the FPSO.

So in summary, a successful 2017 and we're already making strong progress against our planned operational milestones in 2018 including our first operated well in the UK continental shelf where we're close to finalizing a rig slot for this summer. And at this point, I'll hand you over to Eric to talk you through our exploration growth plans.

Thank you Paul. Good morning, everyone.

I'm very pleased to be here with all of you, this is my second results presentations since joining Cairn. We've had another very active year in exploration in 2017 and we're going to continue that trend in 2018 and beyond.

So as you've heard from Simon, from James, from Paul. Cairn is now a full cycle E&P company.

We have production at Kraken, Catcher anticipating FID at Nova this year. But exploration is still a key to our continuing to create value and as we say on the slide here.

A robust portfolio prospects which leads to a number of material drilling targets is critical to that success and my goal is to have consistent results on a three-year rolling average. So as we enter into 2018 our exploration focus is shifting from Senegal as Paul pointed out to a very active UK, Norway program and we continue add acreage to our portfolio including Block you've heard about in Mexico and the new Block in Suriname which we're announcing today.

So first we're going to recap our efforts in Senegal where we've had as you've heard a successful third exploration and appraisal program and as Paul discussed. We're now moving into the development phase.

We've talked through these wells in detail previously so I'll just summarize by saying we drove five wells, all five encountered hydrocarbons both oil and gas. So we're integrating the results of those programs into our view of both SNE field as well as the FAN and FAN South complex and assessing additional opportunities there.

I think as you've heard most interestingly, the SNE North Well which sits here found hydrocarbons in the S500 series below the field oil water contacted SNE which demonstrates that it is separate accumulation and this has very positive implications both there and farther north here in the Spica prospect where data suggest that in the S400 series an oil accumulation could extend well north into it. So our work program for both Spica in some of these other areas have been submitted and approved by the government and so we're now looking forward to developing potential additional opportunities here.

Now if we go to UK, Norway as I said we have entered into an existing phase where we have matured our UK, Norway portfolio and have entered into drilling and as you've heard the Tethys well, spud infected spud on Christmas eve, so we worked 24x7, 365 so have no fear. And Raudåsen well has also spud and all of this as we've talked about before is consistent with our strategy, we build the portfolio, we refine it, we mature it, we drill out the best opportunities and we realize value.

Of course the additional benefits in the UK and Norway is you have an abundance of infrastructure so both standalone and tied back developments are possible in a relatively short period of time and in addition, the tax environment in Norway makes exploration very cost effective. As we've said several times, our plans are to drill up to 10 wells by the end of 2019 and we're targeting over 1 billion barrels of gross under its resource at a very modest cost and what you all know is prolific hydrocarbon basin.

So we've recently had the roundtable on our Norway program in January I know you many of you attended, so I won't go into more detail other than to say as we heard initial Tethys exploration well, the initial vertical well has TD-ed and we're now drilling a side track to that and then the Raudåsen well spud last month is currently drilling ahead and we'll have results on both of those wells very shortly. And finally I'll say, Cairn will be operating our first operated well in the UK this year and our first operated well in Norway next year, so another milestone for Cairn as far as operatorship.

So watch this space as this program progresses. Now we'll move over to Ireland where as you know we completed the frontier Druid/Drombeg dual target well here in September.

Now well both the targets were water vet, we did find excellent reservoir in both intervals. And I want to point out, we took and gain significant knowledge from this well the southernmost well drilled in the Porcupine basin and what we're doing, we're applying those learnings to our 2016, 2018 and 2016, 2019 Blocks where we have a brand new Cairn 3D survey and I've talked about before, this is what we like to do.

We core up in an area, we have multiple opportunities and then the well results whether success or dry hole, we can then apply those results to other acreage in the area and that's how we build and generate synergies. So what you see on the slide from this new Cairn 3D is example from this data.

So here's the seismic line, here's the surface and the sort of yellow and orange events coming through here, those are turbidite channels and turbidite fans that are pounding on our Block, which demonstrates clearly the presence of reservoir on the Block, now that's not the only element we need, but that's a big one and it's really exciting to see that and it demonstrates what you can derive from state-of-the-art technology. So given this encouragement and the high working interest we have on both of these Blocks, we will be looking for partners this year.

Again it's early days here with brand new seismic but that data is showing significant promise, so stay tuned here as well. Now in Mexico, we just continue to mature the prospects we identified in the bid round last year and we're heading to drill at least two wells in 2019, at least one operated by Cairn and the other operated by our partner ENI in Block 7.

Now we're submitting the exploration plan for our operating Block 9 to the government this month, in fact I believe this week and their approval of that plan starts the four-year exploration phase. We're really at the very beginning end although we have done quite a bit of work already.

ENI, the operator in Block 7 will also be submitting the exploration plan for that block this month. And we continue to work the additional offshore bid rounds including around 3.1 which is the acreage you can see on the map marked out in green, so we continue to look for additional opportunities.

And now finally and something I'm really excited about, is we're introducing our entry in Suriname and this basin of course has received a lot of attention primarily from ExxonMobil's activity in Guyana to the West I'm sure you're all familiar with that. Now Suriname as you can see on the map here is a conjugate to Senegal you can see our Senegal blocks the upper right and Suriname here and this is paleo geographic map from the middle cretaceous about 100 million years ago and before the Atlantic Ocean it completely opened.

These were adjacent areas. So what we've done is, we've taken proprietary knowledge we gained from our activities in Senegal to speculate on prospectivity [ph] in Suriname.

So today this is an immature front their license and we need new seismic data will shoot 2D potentially 3D data and we'll have to do lots of work before we know if we have drillable prospects here. But what's really exciting is, we took proprietary knowledge, we applied it in innovative way and it's allowed us to enter a frontier area early and that's often where we realized the most value.

So in summary what I want to leave you with is, we have a robust portfolio of exploration opportunities at a various levels of maturity including drill ready prospects in UK and Norway where we have already started to drill and Mexico which is maturing into 2019 activity and then and 2020 and now we've added more acreage here, so you can see that progression as we move through 2018, 2019, 2020 and beyond. And I expect that before the year out my hope and expectations will announce additional acquisitions.

So in summary I'm really pleased with the progress we made and I look forward to reporting to you on it, the next time we meet. And with that I'll turn it back over to Simon Thomson.

Okay, thanks Eric. So as you can see the company offers a very active program across our balanced business.

The production that we have from Kraken and Catcher provides sufficient capability to invest in a very material program on a multi-year basis of ongoing exploration drilling, but also to ensure sustainability of that cash flow generation through investment in further developments activity in Nova and in Senegal. In terms of the exploration drilling as you've just heard from Eric we're going to be very active in UK and Norway of the coming two years.

Mexico will be added in next year and then you'll see there are various different opportunities that could be added into ensure that we have a continuous program year-on-year of exploration drilling across a number of different plays and basin types. So in conclusion, I thought it was worth looking at back at what we said this time five years ago, at the results presentation back in 2013.

We said then that we wanted to regear the capital base to exploration success. We said that we wanted to access future cash flow generation to fund our exploration activity and that we wanted to have appropriate equity interest in operated frontier exploration.

And if you track forward to today, you'll see that we've achieved those goals within the current business offering. So we have a full cycle E&P business.

We have production. We have that cash flow generations from Kraken and Catcher.

We have line of sight on two developments within our portfolio which will ensure sustainability of that cash flow generation and in deep potential enhancement of it. We have exploration exposure obviously we made that frontier discovery in Senegal, we're very active UK, Norway.

We have Mexico, we have other frontier areas that we will be adding into the portfolio. And we retain the funding flexibility I think most importantly.

Not only to add those further opportunities into the portfolio, but also at a time of our choosing to monetize and potentially affect further returns to shareholders. And with that we'll hand over for questions.

Thank you.

Nathan Piper, RBC. Just wanted to make sure I'm getting the right end of the stick here.

You talk about lot of expenditure across the whole portfolio and historically have talked about shareholder returns, isn't that the - even on our arbitration success and the southern and Senegal that the Cairn business will require a quite lot of those proceeds.

No I mean I think we made it very clear that in relation to India the business planning discounts completely success of the Indian arbitration. So from our perspective when because we're confident in the outcome of that, when we win that case there is any opportunity obviously will look at the business in front of us in that but as an opportunity to effect relatively significant cash return to shareholders.

And similarly in Senegal there may be some redeployment but we perceive but there will be the opportunity for further returns as well.

As in just one net pick question on Nova. The operator of the host platform has got a slightly different view to you guys whether or not Nova is going to go ahead or how it's going to go ahead.

Have you have any comments on what has been talked about or mentioned in there?

Paul, do you want to comment on that?

Yes I think obviously we're in a process of negotiation in respect of Nova, but I think it's if we stand back a little bit, it's everyone benefit to see Nova developed going forward and we're pretty confident and it will be resolved amicably.

It's clear. Thanks.

David Mirzai, Deutsche Bank. First question I suppose goes out on Suriname I'm kind of mindful of comments by some of the explorers of transition zone offshore West Africa and kind of come to decision that wells were drilled there too quickly, too higher risk following initial success several years ago.

Obviously we've seen success from Exxon we're forced to seen a few dry wells at the last 12 months. What can you do really to mitigate that kind of process, is it involved in bringing specific partners who have experience in that area?

Eric?

Well we certainly if we mature this to the point where we wish to move forward towards the well we'll bring in partners but Cairn is fully capable and knowledgeable on both sides of the margin begin as I said the conjugate and as far as mitigation I mean we'll have a full program of 2D seismic, potentially 3D seismic and a fair bit of work before we get to a well decision and in the meantime, we'll continue to see well activity there which will also inform our decision.

And I suppose just secondly under the UK portfolio you have by all accounts a good decent constructive portfolio which gives you good cash flow, but what are opportunities within the UK and the Norwegian areas to improve and the fund and the finance and the scalability of that business. I mean does an acquisition make sense, does a merger make sense?

Or do you quite like the way the portfolio pans out at the moment?

I mean I think we're comfortable the way the portfolio is looking because it's more or less as per design now in terms of offering that combination of production, development activity and a very active exploration portfolio. As Eric has commented a fairly concentrated acreage holding around wells that we're drilling.

I mean I think we're constantly looking at whether there are opportunities to bring into the portfolio in UK, Norway should enhance that value it's a pretty competitive environment we're not wanting to overpay for anything, we'll continue to review if there is something that we think is value accretive then we'll look very hard at that. But I think we don't have to do anything.

James Hosie from Barclays, just a question on the SNE project, you've kind of narrowed the guidance in a number of elements whether it's to plateau production and talk a bit of redeployment the FPSO, what are you going to have to do to narrow the guidance in first oil and what makes it three-year rather than a five-year project?

Paul.

Yes, so obviously we've gone out to tender to the FPSO contractors and subsea community. And we've got a pretty good handle on the opportunity set that we expect to be brought forward.

There are some modification potentially required to those vessels, so that scope will have an influence over the timing and as the overall approval process, but we think at this stage recognized there's obviously both opportunities and risks that window that we've set out previously is still valid. Going forward, once we're through an inter feed, we may well change it.

And just moving our question on the financing, you talked about I think $20 million available in the RBL at the moment, but thinking it's $350 million, $400 million. What needs to happen to get up that level?

Is it Nova being sanctioned? Is SNE being sanctioned?

Or is it about the maturity of the UK portfolio now you're through development?

Well it's not related to SNE, so SNE we're contemplating almost certainly a separate funding solution, debt funding solution. So the increase in the RBL facility in the North Sea will be driven by number of factors, one of them will be the inclusion of Nova once it's sanctioned into the borrowing base and the other two are around the I guess completion of the commissioning phases of Catcher and Kraken.

So under any project financing facility you typically have completion test for assets, once they'd be producing for a certain period of time, once a certain number of wells are on stream and so on, so it's those tests which have either been entirely met or very close to having been met in the next month or so.

So we should assume that you get to $350 million, $400 million this year?

Yes, I mean its six monthly redetermination, so there's one at the end of March and there's another one in September, so through the process of those two yes.

Thank you.

James Carmichael from Peel Hunt. Just on Senegal and the exploration side, I think previously indicated that there might be some exploration drilling there in 2018 obviously that's not in the program at the moment.

So just wondering when you're thinking that you might come back and test any additional prospect over there, is it now likely to be alongside any development drilling? And then just also on Tethys, there's also some mixed message from the NPD website suggesting that the first well was completed as its dry hole another second well is being appraised, so just wondering if there is any color you can provide around what's happening there?

Thanks.

I'll hand over to Eric other than to say we can't maybe your interpretation of the NPD website, we can't comment until the NPD comments in terms of the outcome of the well, we're restricted in doing so on that, Eric?

Yes well I'll start with the second, first. Tethys, the first well we drilled to near the top of the reservoir and had mechanical difficulties then for safety reason we abandoned that first wellbore which was a totally appropriate thing to do, we moved over redrilled that well and so that's the number 14 wells in NPD jargon and we drilled that successfully to TD and all I can say is on the back of that well we're now side tracking.

Relative to Senegal that's correct that it's highly likely that further activity exploration/appraisal within will be in association with pre-development and development activities.

It's Sasikanth from Morgan Stanley. I just had one question on your 2018 guidance.

If you can provide what your cash flow guidance was for 2018 including your hedging and the sensitivity around?

James.

You said cash flow guidance for this year?

Yes.

I mean what we've provided. I mean we haven't given specific cash flow guidance for the year, what we've said is with the North Sea fields on plateau it will be generating about $350 million of operating cash flow at $60 Brent.

For this year I mean I guess the inputs are there to form a view production guidance in the range 17,000 to 20,000 barrels a day on average over the year, OpEx related to that $18 a barrel, there won't be any tax. We're still benefiting from full tax shield on that production.

So it's effectively the production multiplied by your price assumption, less $18 a barrel, so $60 Brent that's in the range of $250 million to $350 million of operating cash flow.

Michael from Citi. Couple of questions, so firstly on Cairn India, to dare I say we're close to knowing the outcome of the arbitration process, but can you maybe say what you could see as the risks that Cairn Indian government could frustrate this process and delay further, with the arbitration in August from a legal perspective.

And then secondly just on the CapEx in SNE, clearly the development drilling is a big chunk of the CapEx so yes 60% of that you said, so could you maybe just talk about what you're assuming in terms of rig rate for that number because clearly rig rates today 200,000, 250,000 what are you assuming for that in the project CapEx? Thanks.

James, do you want to talk about India?

Yes, sure. Well I can say a bit on both and then Paul might want to elaborate on SNE.

On India, you're right it does feel relatively close it's been a two-year process to get here under the arbitration, the hearings are in August we'll then be waiting for the arbitration panel to assure it's award that will be a process that will take a number of months so that's, we're expecting that to be a Q4 event. What can India do to frustrate?

Well look they have not been successful in their most significant efforts to frustrate the process, they're made an application to have the whole thing stayed, they made an application to have the case split up into jurisdictional arguments and merits arguments all of that might have delayed it by many years candidly and that hasn't happened, we've successfully defended that. They were successful in getting a six months extension around document production and the submission of their defense arguments, so the original hearing date was in January that's now been moved to August.

In granting that extension, the arbitration panel were pretty clear that in asking India to practically confirm that would address any timetable concerns that they had and India did that and therefore the tribunal responded to say, they would grant that extension, but they would not be sympathetic to any further request for extension and indeed there is quite a bit of redundancy built into that timetable through to August. Effectively there is not very much happening between March and August in terms of the procedure.

And the other thing that the tribunal said in granting that extension was that they would seek to issue the award as expeditiously as possible in their language after the hearings. So I think in terms of the timetable for the hearings in August.

India has been given a very firm message that should now be a solid timetable. In terms of what else they can do to frustrate the process.

All the process on its successful award in our favor, again the treaty is designed to be sort of last recourse to justice, so it's a treaty award is not appealable, it's final and the enforcement provisions around the treaty award are very strong, so it's an award in our favor will be enforceable internationally. It's not as if we have to go to Indian courts to get our shares back or to get the compensation for the loss of the shares.

So again the treaty is created with a very robust enforcement basis.

And the second point, Paul.

So on Senegal capital guidance. I guess we're still acknowledged we're in low in the market and utilization and not just on drilling units or drilling services but indeed subsea and surf installation, so it's going to be in our view a very competitively thought for number of tenders certainly those that we're hoping, but I don't want to make any promises of how much share cost reduction we could see, but on the drilling side.

I think we sometimes get a little bit fixated on the reg cost and there's no doubt that's coming down significantly compare to see 2013, 2014 cycle. But there's obviously been big opportunity to secure improved cost in other areas and EnQuest and Premier have done a very good job in that regard and respect of Catcher and Kraken.

We've obviously seen prices tendered, but little budget on Nova which is encouraging and therefore I guess we look forward to the next three to four months in terms of hopefully securing attracting prices and structures for us in Senegal..

James Thompson here from JP Morgan, just following on Senegal already. Obviously the plan is to hand over operatorship to Woodside later this year, just because we're wonder if we could update us on the sort of process and timing of that around the relevant document submissions and on that it's the first time for Senegal to approve a development project, what gives you the confidence that it's going to be a done in a timely fashion.

And then just finally, in terms of the development plan you outlined. What is the plan for gas in the first couple of phases development?

Yes, so I guess three parts. In terms of the confidence maybe I can just touch on that, then hand over to Paul.

We've been very closely aligned with the Senegalese with the hope of joint venture. In framing the documentation submission and request and time is for approval to align with them to ensure that they have sufficient time to approve, ahead of elections which are coming early next year.

there's obviously this project and there's the BP Kosmos project both of which require a number of different approval, but I would say that we're relatively confident in the sense of the alignment and the continual conversations that go on with government at various different levels to ensure that everybody is fully aware of what needs to happen and when, but you're right. I mean that's a big area of focus for us to ensure that the permissions and approvals are all achieved within the necessary timeframe.

I think if we weren't aligned in the way that we're with Petrosen with the government might have more of a concern, but I think the knowledge sharing is pretty good, but Paul do you want comment on the other points?

Yes I mean I guess every oil and gas project needs to consult with the people of the country. So you started the journey the public consultation plan has already commenced in terms of describing what an offshore oil project is, what does it look like and what does it mean for Senegal?

As Simon has already stated that even the President and the various ministries are very supportive of the project and in respect of Woodside. I mean we've worked very collaboratively with them, I've made three trips to Australia last year.

Our team we've people [indiscernible] both ways into the organizations and we have a predevelopment delegation agreement. So I guess we're trying to build a position where the transition is very smooth.

Obviously goes through the normal sort of operating committee resolutions, but even the natural plan is to transition sort of through the summer, such that the evaluation report is really the sort of end of Cairn's journey as operator and the exploitation plan is the sort of start of Woodside's journey as operator and hopefully in 2021 to 2023 they'll be looking back favorably on a project that they've executed well, as set out in the original exploitation plan. So we've got good confidence that we're working as well as we can within the overall partnership including FAR and Petrosen.

In terms of, to just to touch on gas similar sort of position there. So there is a general recognition, there will be an initial phase of gas reinjection, but there has been an identification obviously in terms of market capacity and conversion particularly for power.

But that's likely to come in what we call the second phase, whether that's phase two or 1B depending how you view it, which is likely to be a few years after first oil.

Mark Wilson, Jefferies. If you can just clarify the CapEx first oil at Senegal, that doesn't include the FPSO because that's a least scenario.

And then just on FPSO, as you say refurbished FPSO is that project specific or really just a change in the market. I'm thinking obviously Catcher being a new build a few years ago.

And then lastly, you participate in the upcoming Mexico shallow water round? Thanks.

The answer to the first part is very simply, it assumes that effectively all of the FPSO costs are built into the lease.

The redeployment is probably fair to say is a change in the market and probably little bit of change in oil companies overall philosophy in terms of standardization of approach and I guess we're also fortunate in the cycle that we've managed to identify a number of vessels that are available that fit quite well with the capacities that we're looking for and the type of fluids that we have in SNE in respect to both the oil and the gas.

And with respect to Mexico, you can all tune in live on March 27 to the Mexican Government's bid round and at that point you'll determine whether we've bid in the bid round.

Thomas Martin at Numis. Got three questions.

On the sort of RBL side and the project financing side, you spoken about how SNE it sounds like, it won't be feeding into your existing RBL and you've also spoken about how the market is obviously very competitive in the contractor side. So could you elaborate a little bit on what sort of options you're looking at, is it vendor financing?

Is the primary route? Are there other things you're looking at?

Would you consider issuing bonds? Are you talking about some sort of separate bank facility just tied to that project?

Secondly, can you just remind me on the SNE exploration side of it. I think that you have you to ring fence in the development areas, is it aim that you can be able ring fence all of the area including Spica as the SNE development or have I got it completely wrong you don't need to ring fence it?

And also can you be able to hold onto to the FAN system area? And third one was just, are you able to quantify the Kraken realization that you're getting in terms of versus Brent?

I mean James, do you want to talk about. The first one I think [indiscernible] on project finance.

Yes, sure. I can probably deal with the first and the third part and then hand over to maybe Eric to talk about the question around acreage, around SNE.

So on the, I mean it's obviously still relatively early days in defining exactly what the funding solution for SNE is, it's likely to be a standalone, the base plan is that there will be a standalone project financing solution for the SNE project in which all of the joint venture participants will be able to participate. And so the sources of capital for that project financing will be commercial banks obviously, but could also include export credit agencies for example multi-lateral agencies.

The World Bank has been very active in Senegal. There are various pools of capital that we are warming up to participate in, what is likely to be a project financing facility specifically for SNE, for all partners.

so that's the base plan, clearly there are alternatives around that, on our own balance sheet and the other part that we'll look out, but that's very much the base plan. In terms of Kraken realization obviously we sold our first cargo in the year we just reported, so I think you can calculate from what we've disclosed that the realized price there was about $52 of barrel and look at what the prevailing price was at the time.

I mean our marketing agreements are based on a discount over a certain period of time around when the lifting occurs, but anyway the realization at the back end of last year was $52 barrel. The cargo is actually that we sold in this year have tightened that discount range and indeed I think the operator has taught also about selling at around 550 discount on one of its liftings as well.

So I mean the broad guidance, we've given is that we expect for the discount to be around about 10% to Brent. And the pattern is been moving towards that as we sold the early cargos.

Eric, do you want to talk about?

I mean our in turn clearly is to capture as you said ring fence all the area that we see as potential going forward particularly as it relates to potential tie-back to SNE, but that's work-in-progress.

We're running out of time, so maybe one more.

[Indiscernible]. Just a quick question on the full cycle E&P business, could you just tease out briefly how you think about capital allocation to the various units whether that depends on the cycle or whether it depends on the strategy at that particular point in time?

I mean so basically the design it's consistently been when we get to this point, you could roughly allocate half of the operating cash flow to reinvestments in the on sustainability of that cash flow and the other half into ongoing exploration activity. So I mean on rough basis, let's assume $150 million plus or minus per annum on exploration activity wherever that happens to be this year, obviously it's a focus on UK, Norway planning work on Mexico and so on next year will be UK and Mexico and potentially others.

So that is not effected by cycles, the design of the company, the design of the breakevens and so on, is that we can consistently aim to provide that year-on-year exposure to exploration activity. I mean it's lumpy of course, some years it might be higher, some years it might be slightly lower, but you know to have that exposure to a combination of frontier emerging basin and mature basin exploration year-on-year.

Okay, I think that's it. Thanks very much [indiscernible].