Capricorn Energy PLC

Okay, morning, everybody and 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 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 is being webcast as usual, so there'll be microphones available. If you do have a question, please state your name before asking.

I think everybody has been in this room before, but in the event of a fire alarm, you can see the exit sign there. And the master point is outside, in the square.

Okay, turning to the first slide, we believe that Cairn today can create, add and realize value for shareholders on a sustainable basis through a combination of these three things, the full cycle E&P business that we have built, our focus -- continued focus on capital discipline and active portfolio management and the offering of multiple catalysts for shareholder value. And looking at each of those in turn, the full cycle business has the financial flexibility to deliver all of our strategic objectives.

So we have significant headroom available through a combination of cash and a largely undrawn RBL facility. As you know, we have strong cash flow through improved production.

You've seen improvements at Kraken and also continued excellent performance at Catcher. We've got reduced production costs and we have an accretive hedging program.

In terms of the next point, capital discipline and active portfolio management, you've seen the Nova farm-down, the Chimera farm-down and also the asset swap with E&I in Mexico, and all of those, I think evidence our strong desire to realize and redeploy value within the portfolio and that's something we will keep on doing. And in terms of the last point there and the multiple catalysts for shareholder value, that's through the remainder of this year, into 2020 and beyond.

So if you said in the statement today, SNE FID will be later this year, and we're about to enter a very exciting period of exploration activity. So we’ll shortly spud the 150 million barrel Chimera well, which I mentioned earlier, in terms of something that we recently farm-down a little bit of that’s a Cairn operated well, and it should spud towards the end of this month.

Soon after that, we will commence a four well program for 2019 in Mexico, targeting over 0.5 billion barrels. And there will be further wells in Mexico already planned for 2020.

So very active exploration program. And in addition, in terms of catalysts, we obviously await the decision the outcome from the panel, in terms of the Indian arbitration.

There's no update there other than to say we remain just as confident in terms of the merits of our case. Okay, before I hand over to James, a few words on core values.

I guess, we’ve probably been presenting here at Lincolns and Fields [ph] for over 15 years, certainly that I can remember. And each time when you come in, you see posters and video like today.

And they’re always focused around our core values, the three Rs, give and earn respect, building relationships, and behave responsibly towards the environment. And on that latter point, we obviously recognize the requirement for energy transition.

And we also recognize the important role that companies like Cairn will play in terms of continued energy security. We all need to do that in a way that is safe, that is transparent, that is compliant, and that is efficient.

But it is something that we continue to need to do. And so I'm just looking at a little bit more detail on that, we obviously don't operate our production today in terms of Kraken and Catcher, and also Nova when it comes on.

But all of those fall under the EU Emissions Trading Scheme, which reduces emissions year-on-year. And it is worth noting that membership of that scheme will result in a 43% overall reduction in emissions by 2030, over 2005 numbers.

So significant reductions. We’re aligned with the task force and climate change and financial disclosures, and indeed, are working closely with BRINDEX [ph] in relation to a coordinated response on that.

We're committed to the UN Global Compact EITI, and also the performance standards of the IFC. But I think the important thing to emphasize is that that's not something new it’s something that we've always done.

So when the Board and when we look at making decisions, we’ll always come back to the core values all of those core values, in terms of anything that we try and do to create further shareholder value. And on that value point, I'll hand over to James.

Thank you, Simon, and good morning, everyone. So what I'd like to do over the next few slides is firstly, to look at our performance during the first half.

Secondly, have a review of what that means for our guidance for the full year. And thirdly, to set out the strong position that puts us in to take the business forward and to deliver key value capitalists.

So let's start with operating performance during the first half of the year. Net production, as you will have seen is strong relative to guidance averaging 23,700 barrels a day.

That's up 15% on the previous six months, and 65% on the same period last year. Our average crude realized price was $68 a barrel.

And that resulted in first half sales revenue of $257 million. It's worth noticing that Brent prices average $66 in the first half.

So that's obviously a very strong story in terms of crude marketing for both Kraken and Catcher. Average production cost was actually just a little below $17 a barrel, that’s significantly below our original guidance of $20 a barrel for the year.

And that together with the realizations has resulted in a strong operating cash flow result of $200 million for the first half. And from that we reported an operating profit for the period of $60 million, reflecting the successful delivery of our balanced portfolio model.

So, if we look now how that's influenced our guidance for the full year, production has continued to remain strong through Q3 and as a consequence, today, we're upgrading our full year production guidance to 21,000 to 23,000 barrels of oil a day. And we're reducing our expected production costs guidance from $20 down to $18 a barrel.

In terms of hedging, as you can see, we've hedged about 40% of our expected second half production this year with a floor price of $67 a barrel. And so far, we've hedged about 6,000 barrels a day of next year's production, with a floor price of just over $62 a barrel Brent.

I'll move on now to reconciliation of cash flows during the first half and as you've seen from today's financial statements, drawn debt reduced from $85 million to $60 million during the first half, and therefore our net debt position reduced effectively to zero as of the 30th of June. The large blue bar on the left there shows cash inflows received during the period, operating cash inflows from Catcher and Kraken of $177 million.

And there was a working capital increase during the period of just over $20 million. So that reconciles to the reported $200 million operating cash flow from hydrocarbons produced in the first half.

The first three orange bars there show cash CapEx outflow during the period by category totaling $135 million or that's $121 million net of the Norwegian tax effect, which is effectively the drawing on the exploration financing facility of $13 million, which you can see at the top of the chart. So, as you can see, within that exploration CapEx net of tax in the first half was about $56 million and around $7 million net related to the three Norwegian well drilling program, which is now completed.

So overall full year CapEx guidance remains in-line with previous guidance at the beginning of the year and I'll come on to that in the next slide. And then just to finish off here to the period close other cash outflows related to new ventures, admin, financing, other costs and a repayment of debt of $25 million, which took us to the mid-year cash position of $58 million.

So as I said, and as you can see, the updated CapEx estimates for the full year remain in line with our previous guidance. And in fact come in slightly lower displays, including a broader exploration program.

So starting at the top here, capital activity on Catcher and Kraken is relatively limited this year $25 million and the bulk of that relates to completion of the DC4 drilling on Kraken earlier in the year now completed. On the development assets as we’ve previously noted, we sold half of our interest in Nova to around now Dyas with an effective sale date of the 1st of January this year 2019.

So that results in a proportionate reduction for the full year CapEx forecast down to $35 million. Then on SNE obviously project definition and engineering work continues prior to FID expected later this half.

We submitted an updated development plan to the government on completion of FEED a couple of months ago, and significant progress has been made with contract awards, which Paul will come on to talk about. And so our full year cost in relation to this activity for 2019 our forecast at $70 million.

On the exploration side, the capital program for the year remains in line with guidance, the key activity in the second half being the Chimera well in the UK, and what is now a four well program in Mexico following our license swaps with E&I into Block 10. So that's effectively an expanded drilling program, whilst expected capital costs have remained the same.

And then finally, we also have early stage work or earlier stage work and data acquisition in preparation for potential future wells in Nicaragua, Cote d’Ivoire and Suriname. So total capital program for the year $295 million against previous guidance of $300 million.

So before I hand over to Paul, just to reiterate some of those main points, production levels and cash flow realizations for the North Sea were strong during the first half, and we expect them to continue as such at similar levels for the balance of the year. With outperformance in a prevailing oil prices we would expect to end the year again with minimal leverage, putting us in a strong position to continue to deliver our active capital program.

Obviously, the key focus for the second half of this year will be on Senegal significant progress has been made on project definition. And we're now working with a joint venture with the government and with a lending group we’ve appointed to finalize financing and take FID later this half.

We're always considering active portfolio management in order to allow us to optimize our capital allocation decisions. On the exploration side, we farm-down our paying interest in the upcoming Chimera well to very low levels, whilst maintaining a material equity position in the well.

We swap licenses in Mexico in order to gain exposure to additional attractive drilling opportunities. And then on the development side selling down half of our interest in Nova into an attractive asset market has materially enhanced our liquidity position for reinvestment elsewhere in the portfolio.

And in that same vein, we’ll continue to assess our equity positions across the portfolio as we make investment decisions in the future. So overall the balance sheet n the asset base is strong.

And that allows us to deliver a series of material value catalyst as we move forward, and we’ll continue to actively manage both of those in order to allocate capital to the highest potential return and to maintain a balanced asset portfolio. And on that, I'll hand over to Paul.

Thank you, James. Good morning, everyone.

I aim to talk through the UK production results in more detail. I now update you on progress on our developments in Norway, but particularly SNE and Senegal.

I'll start with some additional details on our UK production where we are pleased to upgrade our full year 2019 guidance from 19,000 to 22,000 barrels of oil per day, as outlined in March to a revise position of 21,000 to 23,000 barrels of oil per day. This incorporates a recent planned shutdown in August on Catcher for gas treatment upgrades.

And this revised production guidance has been driven by three factors. Firstly, the Catcher FPSO has performed fantastically well, and its second full year of operation, with production efficiency in excess of a design basis of 95%.

Secondly, in May 2019, the Catcher joint venture was able to agree with a Catcher FPSO provider, a commercial basis that allows a framework for sustained production above the nameplate FPSO capacity. And therefore we can consistently produce at the levels that we've seen recently of 66,000 barrels of oil.

And finally, we've seen a step change in production efficiency on the Kraken FPSO such that it's been much improved in 2019 versus 2018. And in the latter part of the first half, with both process streams on stream, production efficiency on that asset exceeded 80%.

So now I move on and discuss the individual progress and plans for both fields. So Catcher averaged oil production of approximately 13,300 barrels of oil per day, net to Cairn in the first half.

The Catcher area production data continues to demonstrate good pressure support provided by aquifer and injector wells, and generally excellent continuity. In addition, the field GOR is relatively stable and water cut remains at lower levels below 10%.

And therefore, we anticipate a small reserves increase at year-end 2019. Assuming the water cut development follows the forecast trend.

Additionally, the joint venture has supported the Laverda and Catcher North satellite field developments and formal approval from the oil and gas authority was granted last week. The reserves associated with these discoveries will also be booked at year-end.

A key element associated with these developments was reaching an equity equalization agreement within the joint venture in July, with Cairn as a key catalyst farming down from 36% in Laverda to 20%. These two satellites will come on stream in the first half of 2021 and will be preceded by a single infill well on Varadero in the second half of 2020.

And strong appetite remains in the European market for this medium grade sweet Catcher crude. So next Kraken, which averaged approximately 9,600 barrels of oil per day net in the first half.

Three drill centre four new wells were hooked up and commissioned in March 2019, adding two new producers and one new injector to the overall well stock. Subsequent well testing in May confirmed the gross well production capacity in excess of 47,000 barrels of oil per day.

Reservoir field performance indicates that the field water cut has stabilized and is averaging around 60%. And well potential has improved due to the better voidage replacement in the central and southern areas of the field and the stabilized water cut.

Further investment is also planned on Kraken in 2020, with the drilling of a single producer, and injector from the drill centre 2 template to an accumulation west of Kraken called Vista [ph]. The reserves associated with this area will be booked at year end and these wells are expected to come online in the second half of 2020.

The inventory management of critical spares by the operator has helped to contribute to the improved uptime, along with more rapid response to trips by the FPSO contractor. As I've already stated, we look to see further improvement in the FPSO performance in the coming period.

The Kraken crude pricing has continued to strengthen both in light of the current heavy oil market dynamics and a good understanding of the crudes characteristic by a global set of buyers. So, we’ll now move on to our SNE projects in Senegal.

And as a reminder, we are progressing towards final investment decision of Phase 1, which involves development of 230 million barrels from a combination of lower S500 and upper S400 reservoirs. This is likely to be followed by further phases of both gas and oil development by extending the subsea infrastructure, installing gas export facilities and drilling further oil, gas and water injection subsea wells beyond the initial 23 wells envisaged for Phase 1.

2019 has indeed been a busy year for the project. A high resolution 3D seismic survey commenced in July to enhance definition across the field, particularly the S400 sands and potentially may become a baseline survey for a future 4D survey.

The updated exploitation plan, including the findings of FEED, has been submitted to the government and is being reviewed. We anticipate costs will continue to reduce for the current scope and at the point of FID to be below $3 billion.

And as a reminder, the environmental and social impact assessment associated with the project has already been approved by the government. Excellent progress has been made on the drilling site two.

Earlier in the year we awarded the drilling rig contracts to Diamond Offshore for the provision of two deepwater drill ships, the Ocean BlackRhino, currently operating for Hess in the U.S. Gulf of Mexico and the Ocean BlackHawk currently operating for Anadarko in the same area.

These modern units are five years old, have a very strong operational track record and have a unique feature whereby the BOP manufacturer operates and maintains the pressure control equipment on a lease basis. And these contracts are wells based, and will commence in early 2020 and 2022 respectively.

The drilling and completion services contracts have also been awarded and split between drilling, formation, evaluation and sand phase completion to Halliburton and upper completions to Baker Hughes. Both front end engineering and design studies have progressed well, with a full support of the joint venture.

The subsea FEED was awarded to ESIA in late 2018. And this work is now essentially complete with Riser Pipeline and subsea production systems, technical deliverables in the process of being closed out, and manufacturing slots allocated to protect delivery of long lead items to support the start of drilling operations.

All flow assurance studies associated with the subsea production system are now complete. The FPSO FEED was awarded to MODEC in early 2019.

And this scope has progressed well, the tanker for conversion has been identified. It's a sister vessel to recent MODEC conversions was inspected last year.

And as a double hauled VLCC that meets our basis of design for storage requirements. VLCC also has a much larger surface footprint for future facilities expansion.

Requests for quotations or call for beds have been issued to all the main process and utility packages, along with the shipyard conversion work and subsequent integration and commissioning of this 100,000 barrel of oil a day capacity FPSO. And as you can see the project has progressed well, with all of the key components now essentially in place, sitting with Tier 1 contractors familiar with executing projects of this nature in West Africa.

Let's now move on to Nova in Norway. And you'll be familiar with many of the details on this slide.

So I don't intend to go through them all. Although, we've reduced our stake we continue to actively monitor progress and remain fully engaged on the project.

This summer so the preparation for modifications on the Gjøa host platform and a very successful subsea campaign. Two subsea templates were installed before laying 65 kilometres of pipeline and 20 kilometres of control umbilicals.

Next year we'll see the dedicated Nova module installed and the start of development and drilling using the West Mira rig for the drilling and completion of the six planned development wells. And on this positive note and with a backdrop of improved production guidance from our UK assets, and very strong strides towards FID being made in Senegal regarding our SNE oil and gas project.

I will hand over to Eric.

Thank you, Paul. Good morning, everyone.

The watch forwards for our exploration program are active, and dynamic as I’ll explain. But our core values have not changed.

We pursue and execute quality material opportunities, while maintaining exposure to potential game changing prospects in order to add significant value for shareholders. There are multiple catalysts coming up in our drilling program in countries with good fiscal terms, a variety of play types, and in multiple basins.

We accelerated our exploration program in a strong way in 2018, on the heels of our very successful appraisal program in Senegal. And we will continue right through 2020 and beyond with the goal of demonstrating the NAV growth we have committed to.

We have a robust drilling schedule both this year and next. We're in the midst of what is now an eight well drilling campaign in three countries.

And five of those wells are operated by Cairn. We built an attractive portfolio in Latin America, with Mexico the focus of drilling now.

We're progressing opportunities in West Africa with newly acquired seismic data. And have expanded into the Eastern Mediterranean with an operated entry into offshore Israel.

In Europe, we completed three exploration wells in Norway without incident and we are preparing to spud the Chimera well in the UK, as I said, active and dynamic. Now we've completed our drilling program in Norway for this year and unfortunately did not find hydrocarbons.

Now all three wells we’re targeting very material volumes, but they were higher risk prospects focused on either unproven plays, or trying to push proven plays into new unproven areas. And given the attractive fiscal regime for exploration in Norway, it is the ideal place to take additional risk, while trying to expand the proven play portfolio.

So while an unsuccessful campaign in terms of hydrocarbons, there were no health, environment or safety issues, and our first two operated wells in Norway were completed ahead of time and under budget. Now let's move to the UK, and the Chimera well is planning to spud this month.

And this prospect has material impact potential. Now, as I've talked about before, it is a new play in a proven reservoir interval.

It's targeting stratigraphically trapped Heimdal sands, which really are only visible on modern 3D seismic, which took special processing and attribute analysis. Now this prospect certainly has risk it is a stratigraphic trapped prospect, but first Suncor and now DNO have chosen to farm-in, which adds confidence to our thesis.

And we should know the results in a month or so give or take. And in the last UK lease sale, we picked up the adjoining acreage, which you can see here, so that in the event of success we have follow on exploration potential, which as I've said many times is one of our consistent themes, the ability to move on with success.

Now let's focus and switch to Latin America, where we continue to build a mature and exciting program. Now as you've already heard, we've increased our position in Mexico and are on the verge of starting our drilling campaign.

In Nicaragua, with our partner Equinor to mature multiple interesting prospect and leads on newly acquired seismic with the possibility of a well as early as 2020. Offshore Suriname, we have acquired over 4,500 line kilometers of 2D seismic on our offshore block and we're working up opportunities there.

But now, let's talk about Mexico. Mexico is clearly a country which has multiple exploration catalysts for us.

As you will have heard, we are now in four blocks with our entry in ENI's operated Block 10, giving us four wells between now and the end of the year. Now, Block 10 has clear synergies for both Cairn and ENI.

Some prospects that you'll see straddle the block boundaries, and this enhances a hub and spoke concept of pulling multiple fields together as we have numerous targets to chase. And we're particularly happy to enhance our relationship with ENI, which as you know, is the first IOC to bring on production in the basin.

Overall, we're targeting over 700 million barrels of gross unrest resource across our six commitment wells in these three blocks. Now, the schematic you can see at the bottom of the slide gives you a view of the variety of play types, and the different age sands which we're targeting, and the line is anchored here on the east by the world class Zama Discovery.

In addition, the Murphy operated Cholula oil discovery sits due north of our block up here. So we're definitely in a good address to find hydrocarbons.

Now let's turn to the prospects. In Block 9, which you see on the left here, the Alom well is expected to spud by the end of the month using the Maersk Developer.

Alom is targeting multiple stack sands with potential direct hydrocarbon indicators. Now these sands are slightly younger than the well-known Zama Discovery to the East.

Now the Bitol well show on the right will directly follow Alom and is targeting multiple intervals from that proven upper Miocene zone that Zama found all the way down to largely untested, lower Miocene and a legacy in sections. So in essence, we're drilling a frontier well, but in a proven oily basin.

Now let's take a look at our non-operated prospects. ENI plan to spud the Ehecatl well in Block 7 in November following the Saasken test in Block 10.

Ehecatl is a very robust structure being a three way trapped against salt. And it's targeting also Lower Miocene sands, which again have been rarely penetrated in the basin.

So success here will open up a whole new play. Now in Block 10, as you see on the right, the Saasken prospect should also spud this month.

It has moderate volumes, but robust hydrocarbon indicators on seismic in the Upper Miocene. And this represents a quality tie back candidate to any potential hub in either Block 9 or Block 10.

So across our acreage position in Mexico, we have the potential for multiple combinations of hub and spoke developments, which adds flexibility and enhances our chances of commercial success. Now, while our focus has been on the active drilling campaign and remember we’ll likely have three wells drilling at the same time between now and the end of the year.

We do continually aggressively evaluate other leasehold, we remain very active in Africa. Our analysis offshore Mauritania our new 3D seismic is ongoing.

In Senegal, as Paul said, we're in the midst of requiring a high resolution 3D multi-azimuth seismic survey, which will not only be instrumental in the development campaign, but will also be used to mature other potential exploration targets. And in Cote d'Ivoire the operator Tullow plans to begin 2D seismic acquisition over our seven onshore blocks in the coming months and recent fieldwork there has demonstrated the presence of active oil seeps on our blocks.

And in our latest addition to the portfolio, as I said, we entered the Eastern Med being successful in the second Israel offshore bid round, which closed in August. We're operator of eight licenses, which cover over 2,700 square kilometres.

We're chasing both tomorrow like sandstone plays, and Zorro-like [ph] carbonate plays. And our initial commitment of seismic reprocessing here is modest.

And this represents a good example of that long range thinking where we have things that may mature into future drilling targets sometime out. So in conclusion, I want to leave you with this.

We have multiple near-term exploration catalysts in our drilling portfolio, while we continue to mature other opportunities across a variety of plays in perspective basins in countries with attractive fiscal terms. We have a strong, multi-year opportunity set in front of us.

And we're continually screening for additional potential game changers. We are as capable as any operator of drilling wells safely, effectively, and in a way which protects the environment.

We certainly have exciting times ahead for exploration in Cairn. And with that, I'll return it to Simon.

Thanks, Eric. So as you can see, we are, as Eric has outlined, well positioned as a company to deliver a catalyst rich portfolio across the full cycle business that's through the remainder of this year into 2020 and beyond.

As Eric has outlined, we're building further option value in terms of further exploration activity out into the long-term. And I think the other point to reiterate is that that is all underpinned by our full cycle business underpinned by balance sheet strength, and by financial flexibility, and underpinned by continued focus on capital discipline, and on active portfolio management, of which you've seen evidence over the last few months, on which you will see further evidence in coming months and years.

We believe that we do offer shareholders multiple catalysts for value creation in the near and medium and longer term. And we look forward to reporting further news flow to you through the remainder of this year.

So with that, I'd like to hand over to any questions.

Matt Cooper, Peel Hunt, two questions. So first one on the updated SNE development plan, just wondered if you give a bit more detail on that if there are any CapEx implications or production profile implications?

And then the second question, of the four wells that you are drilling in Mexico this year do any of those have flat spots, or amplitude conformance structure? Thank you.

So, Paul do you want to deal with the first point there?

Yes. So the SNE exploitation plan update is fairly simple to be honest, there have been a few refinements, but I would say nothing material.

And it's really just to incorporate the findings of FEED, which is a request from the government in terms of some of the design basis, some of the layouts, and some of the additional details that came out of those front end engineering design studies, including the layouts of products and so forth. But there's no sort of material changes to the reserves of production forecast and at this stage the costs which are still being refined on one or two elements, particularly the drilling and the owners' costs.

Eric?

Yes, and in Mexico, we do see indications of both flat events which could indicate fluid context, as well as indications of conformance to structure. The latter which is more difficult given the potential steep dips in places and the salt which sometimes will make imaging more difficult.

But yes, we have indications of both, and drilling will demonstrate whether they truly are direct hydrocarbon indicators.

Thanks, it's David Round from BMO. Two quick ones on SNE or one quick one actually, to start with, obviously, we've heard a bit from your partners around the timeframe around FID in the second half of this year.

So really just interested in any comments around your confidence of still hitting that target? The second one, I think, Simon, you might have mentioned an attractive asset markets and applying that to SNE obviously, you've talked in the past about a potential farm-down there.

I suppose I'm just wondering we’ve got all the inputs, we know what the projects potentially worth. Is that the type of project you are looking for full value, given the -- what is sounds like an attractive backdrop, or how much would you be willing to leave on the table to entice a buyer?

Because obviously, that has advantages for your balance sheet, et cetera. And, sorry, just thinking about, if you were to leave something on the table would that be likely to be oil price or resource upside?

Thank you.

Yes, well dealing with the second part of your question first, I mean, I think every negotiation is different. obviously, in anything that we do, we're looking to try and extract full value from any discussion, I suppose, when you think about timing, Nova is an example of something where we're taking money off the table, ahead of first production, looking back through time, India is an example of where we waited until first production take value off the table.

So I think in each one of those discussions has a number of different aspects, in terms of, as you say, what's the underlying price assumptions, what's the time into market have fully valued, et cetera? How much other interest is there and so on, so forth.

I mean, what I would say in relation to Senegal, specifically, is that we continue to have incoming interest, but our line remains the same, we will look at around FID, if there is an appropriate transaction that we may take some value off the table, but we don't have to. And that remains the position on it.

In relation to timing, and 2019 FID, I mean, we remain in close discussion with all of the JV, speaking with Woodside, last week, there's regular meetings with the governments and so on. I mean, there is an alignment, no matter what you might hear about other things, there is an alignment to move this project forward to FID.

That's what everybody wants, and specifically, that is what the government want and what they are targeting. So, so we're all working very hard towards that.

Yeah. So that remains the case FID in 2019.

Good morning, it’s Michael from Citi. So a couple of questions, just on SNE, as we're talking about SNE, can you maybe just speak more specifically on the on the financing, where we are?

What needs to be done? Clearly, there's a number of parts with different requirements from a funding perspective.

So can you maybe talk about holistically about the project from a financing perspective? And then just on the sort of UK North Sea area in Norway, I was just wondering if you could provide us with an overview of your assessment of how the strategy has gone since you entered the basin in 2012 with Agora, what's worked, what hasn't worked?

And should we see any changes to that UK-Norway strategy going forward? Thanks.

I’ll let James, answer on SNE financing, I mean, on the strategy and the general entry into the UK and Norway. Yes, I mean, not everything is going to work.

And as you pointed out, we've had a number of wells that haven't been successful. As Eric has been highlighting, what we tend to do is try and move towards more materiality, in terms of prospects, in terms of newer types of plays or extending those plays, and that's higher risk.

So we obviously have had success in terms of -- Nova is an example of that and what you can realize in terms of value. In terms of future strategy, I think, we’ll continue to do what we have been doing, which is constantly honing our efforts around those areas that we see as attractive, technically, first of all, most importantly, and where we think we can build a large position around success.

I mean, sometimes it takes time necessarily I mean, don’t forget Rajasthan was a 16th well before we found Mangala. So I think, everything it would be nice if you had success all of the time.

But I think strategically, you've got to take a longer term view in terms of the -- of any particular basin that you're exploring. And furthermore, I mean, obviously, there is a cost advantage in Norway, but that is not the driving factor.

The driving factor is we're looking for things that we think have sufficient materiality. Eric, I don’t know if there is anything else you want to comment other than that?

No, I think that's exactly right. It's a long-term view.

It's a balanced program. And we do tend to target things that when they come in will make a material difference for shareholders.

Yes, on SNE financing the -- we've appointed a group of commercial banks in the various key roles to move forward with the senior debt financing. And in terms of discussions on or agreements around terms with them, and also with the government to the extent that those interlink that's well progressed and well defined now.

So we've been working towards being ready to press go on the -- effectively on the credit process for that senior debt. On -- in terms of project definition, obviously, all the key contracts have been awarded now.

So from a cost point of view, that's well defined, as Paul has mentioned, there's probably a couple of areas where there's one more turn with the intention of hopefully moving those cost estimates down, but they're in a good place already. And the resource base is obviously well defined.

So yes, we're close to being able to push the button on that.

And just to confirm, on the financing, is it -- do you need to see the end of the arbitration process before the banks will lend?

We are -- if you talking about the far Woodside arbitration we obviously not a party to that. So, I -- you wouldn't expect us to be able to comment on what the potential outcomes or the timing of that is.

What we do know is that everybody in the joint venture and particularly the government is aligned on seeing this project funded and FID in the time frame that we've talked about.

Good morning, it's Al Stanton from RBC. I've got three questions, but they're all very different.

So can I do them individually? Chimera is a heavy oil play?

No, no.

Okay. On the financing, SNE, are you assuming you have to pay for the government's stake?

No.

Rattling through, no, you're not assuming that you're paying for the stake?

No, the PSE is very clear that the [indiscernible] is fully carried through the exploration and appraisal phase and post-FID, post exploitation license award, the production license award that they pay their share of development costs, they have the option to increase their share from 10% up to 18%. And that is very much the basis on which we've been working with the government and [indiscernible] has been making its preparations here.

Right. And then you all sound very happy with what you've got.

So I'm wondering why you bid for Edison?

Well, we wouldn't comment on any particular rumors on what we did or didn't look at. I think the point that I would make is that yes, we are happy with what we've got.

But we continue, like everybody look at is there's something else that's accretive that we could bring into the portfolio, that makes sense to us. But from the point of view of obviously, the financials attached that particular transaction, but also does it fit with our strategy moving forward.

So we continue to look at things, but it's only on the basis that we would only bring it in, if we believe it's accretive.

Thank you.

Hi, good morning. James Carmichael from Macquarie.

Just a quick one on Kraken, sounds like everything sort of going well there two train operations and efficiencies, backup and water cuts in line. So I'm just wondering, what do you need to see there before you get confidence to write those reserves back up, or at least now the gap between yourselves and the operator?

Yes, so I guess the first thing to see is, we fully respect all the views in the Kraken family. And I think across it, we're all striving to improve production potential and maximize economic recovery from the field.

And the second thing I think we should recognize, and I think I said this in March is that reserves are estimated, they’re never determined. So we carry a range of estimates, P90, P50 and P10.

And, of course, we choose and we believe that was prudent at the time and remains prudent to reduce our P50 estimate which we did back in March. We would just like to see sort of longer production data in terms of water cut trend and overall performance in the field, before we make any revisions, actually, which we would do as a matter of normal course of business on a six monthly basis.

But as far as our potential in Kraken, and I guess touching a little bit on Michael's question about the North Sea, we had three assets when we acquired those two companies, chose to sell one of them which was our small stake in [indiscernible] and if we step back and look at Catcher and Kraken performance overall, we're pretty happy with it. And there are still growth potential on both fields.

So we're seeing investments next year on Catcher that we touched on in terms of the satellites. There's a plethora of infill opportunities in Catcher.

And a significant potential in the West side of Kraken which we are going to obviously test with our first two wells next year. So overall, we're relatively happy with both fields.

Thomas, excuse me, Thomas over Numis. Firstly, on SNE, the rig contracts been signed.

And just to be clear, the costs associated with that now set in stone. And I think you said before that 60% or thereabouts of the development costs of rigs -- or excuse me of wells.

So does that mean that you've locked in getting on for two-thirds of the development costs?

Partially, I guess, is the answer to that. So that's the variable element of the costs.

But obviously the other element is the durations. So we're still looking at the optimized schedule in terms of the batch approach which we successfully did for example, on Kraken, can we phased the wells and also looking at the durations in terms of sand phase completions and upper completion.

So an element of it is indeed fixed, as you said, but there's another element which we're still trying to optimize further.

Okay. So the sort of time on the rig is priced, because I think you said it was a rig -- a well based contract, but it's not a fixed price per well then that you've agreed?

No, it's a normal day rate based contract, but the commitment that we will make under that contract will be well based rather than duration based.

On the SNE, FPSO footprint point that you made for future expansions, does that imply that you will have the ship coming to shore in future phases to put kit in?

Can you repeat the question?

Can you just spoke about…

Could you just spoke about having a big footprint there to put on…

It's basically -- there will just be additional modules that would be added. I mean it's predominantly around the consideration of gas export.

So we'll have -- we've got a basis of design of 130 million standard cubic feet a day of gas. So that's more than what we need in terms of gas lift and fuel on the FPSO so as our future phase potentially gas export, which would follow first oil by several years.

We would need to consider export risers and obviously pipeline et cetera to shore. So there's flexibility to do that and there's flexibility, if necessary to expand FPSO.

Okay. So it could be loading modules on to the FPSO offshore…

Correct.

…for future expansions. Okay.

So the other ones were just Catcher reserves, I can't remember now. Did you originally book a higher reserves amount versus premier [ph]?

I remember back in the nautical days, they had a different view.

No, we were very -- from what I recall we're very close to the operator's position, when we booked our reserves.

Okay. And -- sorry almost there.

Just on bigger picture on exploration spend and strategy I mean you touched on it a bit before. But on the one hand, you've got SNE, which it looks to me like you're well-funded for a good period of time on at your current interest.

But obviously, if you're spending $170 million a year on exploration for multiple years, that becomes quite a large amount of money. Looking at the drilling program should we be thinking that the exploration budget for next year is give or take similar to this year's budget?

Yes, I mean, I think year-on-year, I mean, sometimes it'll be higher, sometimes it'll be lower. But the guidance remains around about $150 million is what we would like to allocate towards exploration.

I mean, coming back to your point on SNE exploration other calls on capital. We're always looking at that balance.

We're always looking at the waiting and the balance between development activity and exploration. But at the end of the day, we have viewed ourselves an exploration led company.

We believe it's very important core to the strategy to continue to provide exploration catalysts and that's what we all want to do. So we'll look at that in terms of our thinking around the balance of expenditure in the portfolio without being specific about what we might sell or when.

Thanks.

Good morning. It’s James Thompson from JP Morgan.

Couple of questions from me, just in terms of Senegal SNE seismic program what are you hoping to learn from the more detail view of the S400 sands?

Yes. I mean, so basically, it's primarily look to add to try and improve the overall imaging and connectivity within the S400 reservoirs and potentially new well help in terms of well placement and orientation.

Thanks. And then just in terms of Catcher the Laverda farm-down, what were the terms?

In terms of the…

From 36% to 20%.

Right. Yeah.

Well, we're not going to obviously disclose them, but obviously the key driver there was to ensure that we have the common equity across the joint venture within the Catcher area. So if you recall, [indiscernible] didn’t participate in that exploration well, so we basically brought them into that discovery and ourselves predominantly went from 36% to 20%.

And Premier who held 54% went down to obviously they are 50% operated stage. And from our perspective it was a very smart move because it brings complete alignment associated with production allocation and also metering et cetera on the FPSO.

So we were all aligned to make sure that happened.

Thanks. And then just finally on India, I mean, obviously, when you've spoken to the arbitration panel before they told you to sort of not bug them too often, have you bug them recently?

And have they given you any indications at all about how they're getting on and when you might hear?

We bug them, but we're in we're in regular contact with them. I mean, there's still -- I mean, effectively, they're now in the mode of drafting the award.

So the correspondence interaction is relatively limited, but it's still frequent. So we're in regular contact with them.

And what we know is that they will give us a reasonable, but relatively short period of notice when they're ready to issue the award.

Thank you.

Good morning. It's James Hosie from Barclays.

Another question on SNE, and you're very clear that you believe you can get FID by the end of this year. But have you prepared for the worst and talked to the government about an extension to the PSE just in case?

Well, that would be the job of the operator. But the answer is, no.

We are moving forward on the basis of FID this year.

So the operator had any -- between the JV partners discussed plans for an extension.

There's no plan for an -- plan is to get to FID this year.

Thank you.

Any other questions. No, well, listen, thanks for coming and we look forward to coming back to you with news folks.

Thank you.