Capricorn Energy PLC

Okay. Good morning, everybody.

Welcome to Cairn's Half Yearly 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.

We're very happy to take questions at the end. It is being webcast, so there will be a microphone available if you have a question.

Please state your name before asking it. I’m sure most if not all of you have been in this building before, but if a fire alarm goes off, there’s an exit sign there, next here and the master point is out in the square in front of the building.

Okay. So turning to the first slide.

This presentation today demonstrates continued and consistent delivery of Cairn's strategy to create, add and realize value for shareholders from a balanced portfolio. So cash flows from the Kraken and Catcher field provide our core funding for reinvestment in the development projects to ensure sustainable funding in the long term through cash flow generation but also sufficient funding to invest in our exploration activity as we will come on to summarize have an exciting program, multiyear material exploration drilling.

So as you know, both EnQuest and Premier have recently updated on the Kraken and Catcher fields and James and Paul will provide further updates from us. But I do want to say just a few words on the developments which again Paul will summarize in more detail.

So if you look at Nova, we took FID earlier this year. We expect the PDO approval shortly.

And as a reminder that’s a field that will produce 10,000 barrels a day net to Cairn in 2021 and fits very well with the decline profiles of Kraken and Catcher. And in Senegal, we’ve made really strong progress through the first half of the year.

So tenders are in and being evaluated. We have submitted the evaluation report and the environmental impact assessment.

The formal financing will be launched next month, project financing. James will talk a little bit about that.

And also later this month we will submit the Exploitation Plan for approval by the government. We’re targeting approval by the government by the end of this year and FID in 2019.

The majority of the development planning work has already been delegated to Woodside and we anticipate formal Transfer of Operatorship to Woodside over the next month or so. The first oil is narrowing to the center of our guidance and if you remember we’ve given guidance between 21 and 23 and that aligns also with the partners’ comments in terms of first oil.

And I think important just to remember that at plateau this will provide up to 40,000 barrels a day net to Cairn at current equity interest, so potentially a very large store of value for us for the future. If we turn to exploration in the bottom here, we’ve again had a very, very busy first half both in terms of the preparation and enaction of the current drilling program but also in making additions to the portfolio.

So over the rest of this year and until the end of 2019, we’ll drill up to 11 wells. We’re targeting 700 million barrels unrisked net to Cairn.

Those wells will be a combination of UK, Norway and Mexico. We’re currently in two wells, Ekland and Agar Plantain.

One operated by Cairn, the Ekland well and we anticipate results for those wells towards the end of this month. And in Q4 we’ll spud the Stjerneskudd well in Norway as an Equinor operated well.

And I think at a 30% Cairn equity interest and 160 million barrels oil equivalent is a good example of how we’ve transitioned the portfolio we originally acquired way back when with smaller equity interest and less material prospects to large material potential value upside in the portfolio. And there’s a number of those occurring through the course of the next 12 to 14 months.

If you look at the additions to the portfolio, Eric will summarize those but I think the important point I’d like to say is they’ve been a long time in the planning. So they fit completely with what we’ve been trying to rebuild over the last five years in terms of a continuous stream of exploration drilling potential going out over the next few years.

So we see them as feedstock. Of course not every prospect is going to be drilled.

There will be an internal ranking process. But those with the highest value will rise to the top.

And it’s also I think important to stress that they’ve had to pass a strict hurdle race to be included in the portfolio. But we do see them as a great store of potential value for the future.

Just to touch on India. So we’ve had the final hearing of the arbitration that was in the last couple of weeks of August.

The terms of the hearing are legally privileged. So there’s not a great deal that we can say other than that we obviously confirm that we were confident pre-hearing in terms of our legal position and I can confirm we remain as confident if not more confident post hearing of our legal position.

And we anticipate that there will be a judgment from the panel towards the end of this year and we look forward to that judgment. I guess all of this is carried out against the backdrop of continued focus on managing the portfolio, on retaining balance sheet strength and on capital discipline.

And on those subjects, I’ll hand it over to James.

Thank you, Simon, and good morning, everyone. So in the next few slides we’ll look at the cash flows from the first half, the current balance sheet position and then on to a review of the forward capital program.

So looking first at the key figures from the first half of the year, revenues from oil sales were $172 million on an average realized oil price of $67 a barrel. That’s net of hedging cost of around about $0.90 a barrel.

And that generated operating cash flow relating to the period of $112 million on production from Catcher and Kraken net to Cairn of 14,400 barrels a day with an all-in production cost of approximately $24 a barrel. As you can see from this slide, our hedging position out over the next 12 months or so covers about 7,000 to 8,000 barrels a day, about a third of our expected production base using low cost collar structures with floor prices that have been steadily improving as we’ve implemented that hedging strategy.

And we would expect to continue with that hedging structure over the – along the similar lines as we roll the program forward. Production for the second half of this year is expected to be in the range of 20,500 to 22,000 barrels a day and with those production rates and up time more stabilized, we’ll expect to see that all-in production cost come down to round about $20 a barrel in the second half.

Turning to the balance sheet position at the half year, cash at 30th of June was $75 million and there was a receivable for production during the period that was paid for post period end to $55 million and that’s what’s being included in the operating cash flow number of 112 that I just mentioned. The current Norwegian tax receivable relating to exploration expenditure undertaken in 2017 and '18 of $62 million is roughly equal to that which we’ve drawn under the Norwegian exploration financing facility that we’ve put in place to advance those tax rebate cash flows.

Drawings under our North Sea reserve base lending facility at the midyear was $65 million and we’ve recently executed an agreement to extend the maturity of that facility, that $575 million from 2021 to 2025 and that will allow us to fully incorporate the Nova development into the borrowing base and to continue to maximize funding, headroom and flexibility. Looking forward out into the longer-term sustainability of our producing asset base on SNE, work with government and partners is well underway to launch project financing with potential lenders in Q4 of this year following submission of the Exploitation Plan and that will be in readiness for funding close and availability roughly in conjunction with FID in the middle of next year.

And lastly, as Simon has mentioned, the final hearings of our Indian tax arbitration concluded recently in The Hague and we continue to expect the positive outcome in due course. But importantly our long-term business plan remains fully funded without taking into account the expected proceeds from successful enforcement of our claim against India.

Turning to the next slide, we set out in more detail the cash flows from the first half of the year. The opening cash position was $86 million and cash inflows during the period were $57 million of operating cash flow, $29 million of drawings under the exploration financing facility in Norway and as mentioned $65 million of drawings under the RBL facility.

Outflows during the period; $61 million of ongoing development spend on producing assets, Catcher and Kraken; $25 million of predevelopment spend on the SNE and Nova projects; and $59 million of exploration expenditure which included the Tethys and Raudåsen wells earlier in the year in Norway and ongoing early stage exploration across the portfolio. So taking into account G&A, finance cost and FX adjustments of $17 million during the period, the closing cash position was $75 million.

Looking now at the capital guidance for the – CapEx guidance for the full year, $135 million of expenditure on the two producing assets will effectively see the completion of this stage of field development and the conclusion of development drilling programs on both fields. Formal government approval for the development plan, the PDO on Nova is expected shortly, as Simon has mentioned, and on that basis we forecast $45 million of development spend on Nova during 2018 out of a total $200 million net to Cairn to take that project to first oil in 2021 as previously guided.

$30 million on SNE in Senegal will take us through to entry and to FEED I expect later in this year which Paul will come on to talk about in a moment. On the exploration side, activity this year continues to focus on drilling in the UK/Norway region as well as preparation for commencement of an extensive drilling program in Mexico next year, and the addition of new ventures which we’ve announced both today and earlier in the year of Mauritania, Suriname and Cote D’Ivoire.

So as you can see, the expected net of tax exploration spend for the full year currently stands at $120 million. So in summary then a continued healthy balance sheet position together with the establishment of our production base puts Cairn in a strong position to continue to invest in the long-term sustainability of that production base but also in an active and material exploration program with a strong new ventures pipeline.

And on that point, I’ll hand over to Paul.

Good morning, ladies and gentlemen. I’ll talk through the performance and progress on our production and development assets and we’ll start with Kraken and Catcher.

The picture obviously shows the offloading of the crude package from the Kraken FPSO. You have no doubt received the recent feedback on the performance of Catcher and Kraken from the respective operators’ half year results.

We will try to give our own color on the asset performance of each. Catcher is performing slightly above FDP, field development plan, expectations producing around 60,000 barrels a day fairly consistently and the FPSO has produced at levels of up to 70,000 barrels a day for short periods.

Reservoir and well performance appears strong as we continue the full commissioning of the remaining systems and iron out a few final issues with the FPSO contractor. In H1 we produced an average rate of around 27,000 barrels a day but expect to exit at about double that rate in the second half.

Drilling is nearing completion with the Ensco 100 rig operating on well number 18, the final well versus 22 originally anticipated in the field development plan. There is likely to be some additional infill and satellite wells in the field and the operator is working hard with the joint venture to mature those opportunities for 2020.

Kraken performance is an improving picture but slightly below the FDP expectations. Although we reached 50,000 barrels a day in Q1, we are now consistently producing at stable rates between 35,000 and 40,000 barrels a day with much improved and more consistent voyage replacement as the water injection system is performing more reliably.

We are likely to exit 2018 at these sorts of levels due to deferred drilling on DC4, planned well tests and water cuts slightly higher than expectations. In each one we produced an average rate of 30,700 barrels a day due to the voyage replacement challenges, planned maintenance in March and the overall FPSO uptime being lower than originally anticipated.

We’ve been running the boilers and power generation on crude to help reduce diesel consumption which should help bring OpEx in the second half slightly lower than in the first. Subsea Drill Center 4 is nearing completion which will allow the Transocean Leader semisubmersible rig to return later this month to drill and complete the remaining three wells for this phase of the development.

Additional potential remains predominately on the west of the field and we’re likely to pursue these opportunities in 2020. Moving on to Nova.

Back in March we were posed several questions regarding the commercial arrangement for the Nova development. As we predicted and with the support of the ministry, we were delighted to reach a mutually acceptable commercial arrangement between Nova and the UR [ph] partners to facilitate the processing of oil and gas from the Nova field.

This 1.2 billion project was the first to have its PDO successfully submitted on the Norwegian Continental Shelf in 2018 and we expect approval very shortly. It will develop approximately 80 million barrels, produce at a plateau rate of up to 10,000 barrels of oil equivalent net to Cairn and generate significant levels of cash flow for Cairn in the period 2021 to 2023 when we anticipate being in the execute phase of the SNE development project in Senegal.

This will be the third subsea development by operator Wintershall on the NCS and we’d like to commend them on reducing cost between concept select and sanction by 30%. So moving on to the SNE and our oil and gas project in Senegal.

We have made significant strides forward in 2018 and achieved several of our planned milestones already. It has been particularly encouraging the level of engagement and support from the respective ministries and Petrosen, the national oil company in respect of the first offshore oil and gas project in Senegal.

We have submitted the environmental and social impact assessment in June which was quickly followed by a copy of the evaluation report which I have today here. We have received positive responses to a tender process for the subsea FPSO drilling rig and oilfield tubular.

Evaluation is ongoing having shortlisted several suppliers already in certain select areas. The fundamental philosophy of a phase development remains unchanged.

And although we have presented a window from 2021 to 2023 for first oil, the base case is now narrowing to 2022. And this slide captures the flavor of the project that was set out in the evaluation report.

We currently envisage three phases of oil and gas development. Phase one which focuses on the 500 series reservoirs and a core area of the 400 series will develop up to 240 million barrels of 2C resources.

Gas is likely to form part of this first phase, most likely one to two years after first oil. Phases two and three see a natural expansion of the core subsea infrastructure and potentially some facility enhancements with each incremental phase developing around 120 million to 130 million barrels.

This is obviously further refined and the detail of the final plan will be contained in the Exploitation Plan or development plan which is being prepared in consultation with ourselves by our joint venture partner Woodside. We are targeting submission of this plan by the end of September.

The PSC then allows for a three months review period from submission before approval, so we would expect to receive this by year end or early new year. There has already been good engagement on the project, there’s a high level of interest in country and a joint venture aligned on targeting first phase CapEx of below $3 billion.

The supporting finance plan is well underway and as mentioned by James will formally launch shortly after submission of the Exploitation Plan. And finally Transfer of Operatorship is likely to complete by year end with the arrangement already well understood and Woodside already working with the support of the joint venture under a development delegation agreement.

So in summary, we are seeing an improving production and facility performance on Kraken and Catcher, we have sanctioned Nova and we are putting the foundations in place for an excellent oil and gas project in Senegal that has the potential to be a long life, cash generative asset in our portfolio. And on that note, I’ll hand over to Eric.

Thank you, Paul. Good morning, everyone.

So the focus on exploration today as Simon said is very much growth in our exploration portfolio. We’ve added attractive opportunities which have the potential for significant impact for Cairn.

We are growing the portfolio just as we have consistently said we would do and we have expanded our play diversity and we’re high grading our portfolio to pursue the very best opportunities. We have the skills and capacity to move into new areas and to mature plays in a wide variety of geologic settings.

We are not constrained by geography or play type. Also, we’re maintaining fiscal discipline while we pursue these compelling projects.

As I’ve said before, our goal is to be capitally constrained not opportunity constrained. The common elements which drive our hunt for new opportunities include good fiscal terms, plays which could be transformational in scale, a clear path to commerciality and the ability to monetize if we choose at an attractive valuation and of course working with excellent partners in our pursuit of high impact exploration.

So you can see here the most recent additions we’ve made; offshore in Mauritania, onshore in Cote d’Ivoire as well as our recently awarded block in Suriname. Now our focus remains predominately on frontier and emerging plays with significant impact potential, but we’re also very active in the UK and Norway where we continue to identify and capture high-quality opportunities with shorter cycle times.

Our farm into the Plantain prospect in the UK North Sea is a good example of that and that well is drilling as we speak. So look, our focus in exploration remains on good fiscals, good rocks and a clear path to commerciality.

So the next three slides I’m just going to do a brief review of our expanding exploration portfolio and I’m just going to hit the near-term highlights. So in Latin America and Mexico, we expect approval of our exploration plans in both Block 7 and 9 next month and we’re on track to drill in both blocks in 2019, including our first operated wells in Mexico.

In Suriname, we signed the PSC with the government in June and we’re preparing for 2D seismic acquisition which we hope to kick off at the end of this year or early next year. And this block at almost 12,000 square kilometers is the largest block offshore Suriname.

Now if we turn to Africa, in Senegal as Paul said definitely our focus is on development of the SNE field but we do continue to mature potential tieback opportunities. These could include the FAN discovery, the SNE North discovery which you’ll remember actually found oil below the oil water contact of SNE field and the Spica prospect.

So the focus here is to be prepared for any potential M&A activity when a rig comes back to the field. In Cote d’Ivoire, we have returned to onshore exploration with our partner and operator Tullow Oil.

We have a 30% working interest in seven blocks that are targeting a continental rift play analogous to the world-class discoveries that were made in Uganda and Kenya, plays discovered and built by Tullow Oil. Now a significant benefit here is a clear path to commerciality with oil and gas pipelines in close proximity, oil refineries nearby and a deepwater port with the facility to ship oil.

So in Mauritania, we have now announced a 3D seismic option with the operator Total in their C-7 Block. So we have the right to acquire up to a 30% working interest upon a well decision following completion of the seismic program and full geological and geophysical interpretation.

This is a very innovative deal for us at a modest cost in an area which is seeing significant interest and where majors have recently paid signature bonuses in excess of $70 million. So we’re quite happy with this opportunity.

Now I’d like to turn to Europe whereas I said and Simon said we have two wells drilling in the UK and we have a further well in Norway to spud in the fourth quarter. Now both the Cairn operated Ekland well and the Plantain well operated by Azinor had some issues in the shallow hole so we’re a big behind schedule but now both wells are moving forward and we expect results by the end of this month.

And at Plantain we do have the option to assume operatorship after the well results are digested and evaluated. In Norway, Equinor will spud the Stjerneskudd prospect late in the year and this is quite a significant prospect for us with a mean gross volume of over 160 million barrels and where we have a 30% working interest.

Now my final slide is really a summary of our exploration program over the next three and a half years. Hopefully as you can see we have a very busy 2019 ahead of us following a six-well program in 2018.

And to reiterate what Simon said, this will be 11 wells in the next 16 months. So we’re going to be busy.

We’ll be testing prospects in Mexico, as I said, including our first operated wells and our first operated well in Norway and a significant well test in the Barents Sea. Again, as Simon said, we’re targeting over 700 million barrels net unrisked to Cairn between now and the end of 2019.

And we are on track to drill 10 wells in the UK and Norway by the end of 2019 which is exactly what we told you we would do back in January. And in the out years you can see we have significant optionality in our drilling program.

Of course, some of these opportunities will be matured and drilled, others will not. Look, that’s the fluid nature of exploration and managing a prudent portfolio.

So we now have a robust exploration portfolio which we believe will contribute significantly to our net asset value growth. And we have multiple operated assets which will give us flexibility both in attracting partners and reducing capital exposure.

Meanwhile, we do continue to search for additional compelling opportunities with which to further upgrade our portfolio of opportunities. And with that, I will turn it back to Simon.

Okay. Thanks, Eric.

So as you can see we’re on plan. Our production is sustainable over the long term through developments already within the portfolio.

We’re funded to pursue those developments to ensure that long-term cash flow generation but also to continue to invest in a material program of exploration drilling over the next few years. Balance sheet strength and capital discipline remain absolutely core to everything that we do and that allows us to actively manage the portfolio at a time of our choosing.

So we believe we’re well placed to deliver on the model that we’ve been building over the last few years. We feel it’s in the right place.

We look forward to coming back to you with results of exploration drilling of progress on our developments and obviously with the outcome of India and pursuing generally the strategy of creating, adding and ultimately realizing value for shareholders. With that, I’d like to hand over for questions.

Nathan, straight up.

Good morning. Nathan Piper from RBC.

A couple of areas to focus on, if I may. First of all on Senegal.

You talked about gas, which you have mentioned before, but can you be a bit more specific about having to include that as part of the phase one? Could you give a little bit more color as to what commercial arrangements you need to put in place to make gas – how you’re going to make the gas work?

What infrastructure you need to put in? What kind of volumes you might look to exploit in the first phase?

And what kind of gas price you’d need?

Sure. Paul?

Yes, it’s probably worth saying some context first, Nathan. So there is a fairly significant gas resource in the greater SNE area, really that comprises three elements.

So there’s the associated gas which is fairly modest. There’s the volumes of gas cap, gas line even directly over the oil which wouldn’t be exploited until we move towards the end of the field.

And there’s fairly significant volumes of non-associated gas which are in separate reservoirs. So in totality looking at something around 2 Tcf of potential sales gas.

Obviously we’re still in discussions with the government and with Senelec, the electricity power generator in country. I think it’s too early to start talking about the details of the commercial arrangements but there’s good engagement.

There seems to be a desire to bring gas from this project post first oil and we would anticipate as I said that may come to fruition a couple of years after first oil.

There’s going to be opportunity to seeing a material CapEx event after – obviously a big CapEx in first oil but then another nine significant CapEx event against first gas or is that a wrong way to think about it?

Yes, that’s probably the wrong way to think about it. The volumes in terms of off-take we’re sort of looking at are around 60 million standard cubic feet of gas initially, so we’re probably looking at sort of one or two satellite wells and a pipeline into Dhaka [ph]

Okay, yes, that’s fair. And just last one on Senegal, given the maturity of the project, are you getting more reverse inquiries on Senegal or is there more engagement in Senegal in general from the wider industry?

In terms of the interest in the asset itself?

Yes.

Continuing I would say. And obviously as you move towards greater certainty and FID that is when from an industry perspective things are derisked.

So as we said previously, we have the capability to take this through at the current equity level if we choose to, but a natural time should we decide to take any equity off the table will be more on FID. But yes, there continues to be interest in the project.

Just one last one on Mexico, given the change of government, how are you seeing the CNH working? And you talked about approvals needed for your exploration next year, how are the actual mechanics of government working underneath whatever the President say?

Yes, positively.

Yes, we’ve had no reduction in forward progress so far, so we remain confident that we’ll move ahead and get our wells drilled.

That’s good. Thank you.

Sasikanth from Morgan Stanley. I have a couple of questions on project financing.

Essentially the dispute between FAR and Woodside, does that hamper your discussions on project financing at all? Does that need to be settled before you move ahead with it?

Are you still looking at a 50% debt to equity ratio on project financing?

James?

So on second part of the question I think work is significantly progressing and getting ready to launch this financing with potential lenders. The resource base has been independently audited.

We’re finalizing the process of cost estimates and independent review of cost estimates that we’ll feed into the Exploitation Plan and ultimately the banking cases. So on that basis I think the prior guidance of around about 50% target leverage remains about right, bearing in mind both the nature of the project and it lends itself to leverage in terms of the fiscal terms and so on, reasonably fast payback from the equity of the cost recovery process but also obviously Senegal is a new country for project financing at this scale.

So weighing those two things together I think that that guidance remains current. In terms of the arbitration between FAR and Woodside in relation to the previous sale of an interest by Conoco to Woodside, that is a dispute between those two parties.

It’s at the side of the joint venture. The joint venture and the project is moving forward.

We’ve been working together on preparation for project financing and we continue to plan to launch next month once the Exploitation Plan has gone in.

And just a small question on the CapEx. The less than 3 billion CapEx that you highlight for phase one, is that still in line with the guidance that you had previously to first oil, the $2.2 billion to first oil?

Yes, we talked about net to Cairn CapEx to first oil of around about $800 million.

Thanks. It’s David Round from BMO.

Can I just – one quick question on timing around Senegal because I know you mentioned 2022 but I guess we’ve got a range of 2021 to 2023 still which is quite a wide range given we’re almost in 2019. So the question is perhaps you can talk around the steps that would see you actually reaching oil in 2021, first oil in 2021?

And then the key risk, what are you most worried about that could potentially push that into 2023? What’s the critical path there?

Paul?

Yes. I think there’s obviously some commercial sensitivity because we’re looking at a number of options.

We’re still in that tender process in regarding subsea and FPSO redeployment versus conversion. So I don’t really want to speak too specifically about those elements.

But obviously getting the approval process underway, getting granted the 25-year Exploitation license and delivering and certainly in the short term from my perspective over the next six months through frontend engineering and design, that’s where I see as sort of critical line of sight that is going to obviously potentially impact the schedule. Thereafter, after sanction it’s really about the basis of the design that we’ve selected, FPSO being a key one.

Okay. Perhaps maybe just a quick follow up.

So if we saw FID early next year, would we be looking at 2021? And if it was late next year, would that be leaning more towards '23?

Yes, I would delink them. I would just basically go with our mid guidance of 2022 and the FID as we have guided before, like in any project there’s as I say I worked P50 [ph] base case so there will be opportunities to try to accelerate that and there will be risks that potentially could delay it.

But our base guidance is 2022 today.

It’s Stephane Foucaud from GMP First Energy. I’ve got a question on the water cut on Kraken that you mentioned and perhaps you can provide some color on this.

So first around what sort of level have you reached, excluding the water from the jet pumps? I was also under the impression that the water cut stabilized since May.

Is it in the case? And perhaps lastly, is the water cut coming – it’s a uniform situation or is it more coming from some areas?

That’s my first question. And second, to put it quite straightforward, what sort of size are we thinking about for the prospect in Mexico?

Thank you.

Do you want to Mexico first and then Paul can do --?

Repeat the question…

What size are the prospects in Mexico?

Well, we haven’t put out guidance on that expect to say they all are above our minimum economic field size and we’ll be – if successful we’ve commercial in those water depths less than 500 meters. But we’ll all have to wait and see what the results of the wells are.

But we’re looking forward to drilling them, I’ll say that.

[Indiscernible] order of magnitude, are we talking hundreds of millions, tens of millions --

Well, you can imagine in the fiscal environment and those water depths they’ll be well in excess of 100 million barrels. But you can do that back of the envelope.

We just put Kraken performance in perspective, there’s really sort of three factors and EnQuest as operator have discussed some of those. There’s a voyage situation.

The water injection system wasn’t performing as we had – as well as we had hoped. So at one point we were about 1 million barrels deficit in terms of voyage or the amount of oil and water that we’ve extracted versus what we’ve returned to the reservoir to maintain the pressure.

So that’s been no doubt the dominant factor in terms of impacting production performance. The second one is obviously the facility itself which is obviously the uptime.

There’s been a number of trips some of which were unfortunately down to weather. We had the beast [ph] from the East in March and then we had a number of facilities trips in the second quarter.

And then the third one is for a heavy oilfield, we anticipated early water breakthrough and that’s what you’ve got when you got a crude which is 100 times more viscous in the water and we were sitting at expectations or around 30% water cut and we’re a bit higher than that. We’re about to go through an extensive well testing program to try and better understand that and just think about where we want to distribute the water within the field.

Just now it’s pretty uniformly being injected across the field should we distribute more in the North and the South versus the center, and these are some of I guess the plans that the operator is contemplating in terms of trying to optimize the performance of the field further.

The 30% you’re getting, is it in all the wells?

No, that’s a field-wide level. That’s why we’re basically doing the specific well test now to better understand how is that distributed between the wells.

And lastly, how does that compare with what you are expecting at that point of the project?

Yes, I think I’ve already addressed that one, Stephane. It’s – the actual is at a field level is slightly higher than what was originally expected.

It’s 10% higher potentially.

Thank you.

Okay.

Good morning. It’s James Thompson from JPMorgan.

Just wondered if we could just flesh out a little bit on the exploration program. Obviously you’ve outlined quite a few wells over the next three to four years.

Just in terms of budgeting process really more than anything, can you talk a little bit about how much you think you can allocate to new ventures through '19, '20? And how we should think about the cost of that exploration program through 2019, 2020?

Looking at potentially 10 wells next year, it feels like it might go over sort $150 million, $160 million. Just a little bit more color on the cost and the budgeting process associated with the exploration the next couple of years would be great.

Thanks.

James?

Sure. Look, I think $150 million remains the right guidance and indeed on the program that Eric highlighted on his last side there, that is the expectation for next year.

Now that’s the guidance on average. It’s always lumpy of course.

It will depend in part on exactly how many wells in Mexico come into next year versus 2020. But that guidance is about right.

And then obviously beyond next year, the commitments are relatively small but we’d like to think that the pipeline that can deliver prospects and wells is relatively strong. So there’s quite a lot of flexibility around that.

But in terms of planning, $150 million remains the right guidance.

Okay, great. And then just sort of following on from that, could you talk a little bit about just the exploration market in general?

Clearly, you’ve been able to access quite a few different areas over the last short period. Is it becoming more competitive?

Are you at risk of paying signature bonuses and things like that in the interim, a little bit more color there would be great?

I’m not sure it’s become more competitive because we never saw it become significantly less competitive. I think even through the downturn, the competition was more robust than lots of people anticipated.

I will say we are seeing now increasingly activity by especially the majors and super majors; Petronas, Shell, Exxon, Repsol, others are moving in. So I think everyone is recognizing now is the time if you’re going to ramp up activity to do it with sustained product prices we’ve seen it.

But we’ll remain fiscally disciplined and we’ve been able to capture opportunities as you’ve said and we’ve been fortunate in that way and we’ll continue to fight the good fight every day. But we’re going to remain within guidance and do the right things and not overpay.

Just to pick up on that, Eric used the example of Mauritania and other signature bonuses. But if you look at the Mexico and the kind of subsequent bid rounds after we established our position in Block 7 and 9, there were a number of areas that we were potentially interested in but the signature bonus from our perspective was too high to contemplate in terms of the allocation of capital going forward.

So we’ll remain disciplined in terms of the approach. And if there’s things where people are prepared to put a lot of cash up front, then that’s our goal.

Hi. Good morning.

Mark Wilson with Jefferies. I’d like to understand the specifics of the Exploitation Plan in Senegal versus a final development plan at some point in 2019?

Can you just give us an idea of what you laid down? Is it a well count or is the Exploitation more framework?

No, actually the evaluation report is more of the framework and the Exploitation Plan is I guess those of you that are old enough like me in the room to call out mini Annex B [ph] from the UK. So it’s very much a few development plan but it envisages the life of the field, so it has several phases set out.

But obviously with a natural focus from a government and obviously from the partners’ perspective on what the first phase looks like. And so as a [comparison], we’re already looking at probably one or two fewer wells in the phase one Exploitation Plan than what we submitted in the evaluation report and that’s really just because within that framework there’s a little bit of optimization that’s going on and we’re probably looking at more like 24 wells rather than 26.

And I’m sure by the time we actually execute it as we’ve done on Catcher, we started with 22 wells anticipated in the FDP and we’ve executed 18 and there might be 19 or 20. On Kraken, we envisaged 25 and it looks like we’re going to drill 24.

But the [sets] are very clearly the core subsea and infrastructure and the overall architecture, all of the floor assurances done and obviously the facilities basis of design are specified in a generic way which will be then detailed depending on who we select for FEED.

By the end of the year if Senegal approve that Exploitation Plan, that’s a very clear technical development plan?

Yes.

And is the approval of that plan therefore connected to the operatorship of Woodside you talked about around the end of the year for Woodside, and do they want to see that approved before they take that up?

As I said earlier on, I guess the operatorship in some sense is already happening in terms of transition because of the amount of work that’s being delegated to Woodside. And so we anticipate it will formally happen next month probably.

It’s not connected as such, so the government is approving from the point of view the JV, the development of the field rather than the operator itself. But we anticipate that will happen ahead of it.

And then secondly, I feel we should touch on India a bit more, Simon, regarding the continued government sell down of their [ph] stake and how that ties into let’s assume a successful decision of The Hague?

Yes, it’s a cash claim. So from our perspective the selling of the shares doesn't make any difference to the amount that we’re claiming.

But James, I don’t know if you want to comment on --?

Yes, the two are not linked. So our claim for compensation under the treaty, so our claims outlines why we think the treaty is being breached and assuming we’re successful in demonstrating those breaches, then the compensation claim is to return us to the position we would have been in January 2014, but for the actions of India.

And obviously we haven’t had access to those shares during all that time. We were about to sell them for just over $1 billion in January 2014.

So is that plus the other losses we’ve suffered during the period that is the claim. So what they do with the shares in the interim doesn’t affect the nature or enforceability or finality of the claim.

And so recovery of a cash claim would go by what mechanism?

Well, the award assuming it’s in our favor when it’s issued will set out the terms on which India is required to meet that compensation claim. We envisage the compensation claim will be characterized in a monetary amount and then that would be the amount due to us under the sovereign treaty from India with payment terms set out by the tribunal.

Thank you.

James Hosie from Barclays. Just on project finance for SNE, who’s actually responsible for leading that?

Is it ourselves or is it Woodside, is it the next operator or is it something that JV does together? And then are you pursuing alternatives for project finance, say, more conventional RBL lending?

The baseline is very much around the project finance facility that all partners can participate in, all four joint venture partners. And the preparation for that has been – there’s a subcommittee appointed which has been meeting very regularly.

As I said, work is well progressed in readiness to launch. And that is really a partnership of the government, the four partners and the bank and legal advisors that we’ve appointed to.

So it’s been all of those parties working together.

And is there export credit? Is that the sort of avenue you’re going down with this?

We envisage that ECAs may well play a role alongside commercial banks, yes.

Okay. Thank you.