Half Year 2015 Cairn Energy PLC Earnings Call
Aug 18, 2015 AM EDT
CNE.L - Cairn Energy PLC
Half Year 2015 Cairn Energy PLC Earnings Call
Aug 18, 2015 / 08:00AM GMT
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Corporate Participants
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* Simon Thomson
Cairn Energy PLC - Chief Executive
* James Smith
Cairn Energy PLC - CFO
* Richard Heaton
Cairn Energy PLC - Exploration Director
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Conference Call Participants
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* Alex Topouzoglou
Exane BNP Paribas - Analyst
* Stephane Foucaud
FirstEnergy - Analyst
* Anish Kapadia
Tudor Pickering Holt - Analyst
* Dan Ekstein
UBS - Analyst
* David Mirzai
Societe Generale - Analyst
* Sanjeev Bahl
Numis Securities - Analyst
* Rafal Gutaj
BofA Merrill Lynch - Analyst
* Jamie Maddock
Morgan Stanley - Analyst
* Nathan Piper
RBC Capital Markets - Analyst
* James Hosie
Barclays - Analyst
* Ritesh Gaggar
GMP Securities - Analyst
* James Thompson
JPMorgan - Analyst
* Brendan Warn
BMO Capital Markets - Analyst
* Charlie Sharp
Canaccord - Analyst
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Presentation
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Simon Thomson, Cairn Energy PLC - Chief Executive [1]
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Morning, and welcome to the webcast of Cairn's half-year results presentation. I'm Simon Thomson, Chief Executive, and with me are James Smith, CFO, and Richard Heaton, Exploration Director.
So, as in the usual way, we've got a presentation we'll run through with you today, and at the end we'll be very happy to take your questions.
So, if we turn to page 4 of the presentation, I'll provide you with a brief summary. Cairn's strategy is straightforward. We seek to deliver sustainable value growth for shareholders from a balanced E&P portfolio. So on the one hand we have a combination of cash and future cash flow from our mature basin position in the UK and Norway, and on the other we have exposure to material positions in frontier and emerging basins, with Senegal obviously currently the core area of focus for us.
The current oil price environment presents challenges to the industry, but it also presents opportunities. Against a backdrop of the Indian tax issue and falling oil prices, we took early action last year to reduce costs in the Group.
As a result, we remain fully funded to deliver all of our strategic objectives, to allocate capital to value enhancing projects and to benefit from an environment of reduced operational costs. Importantly, in assessing the balance of political, technical and commercial risks across our asset portfolio, we've targeted assets that remain robust in a low oil price environment, with attractive breakevens.
Let me give you a brief update on the Indian tax issue, where the tax authorities continue to enforce a restriction upon our shareholding in Cairn India. It's 20 months since the investigation began, and Cairn is doing everything possible to press for resolution and to move the process forward.
We would like the Indian government to move to arbitration, so that we have clarity in the process. We remain very clear on the strength of our legal position on this issue, which we have confirmed is ring-fenced to India, but we cannot today provide you with a clear timetable for resolution.
We do, however, believe that early resolution is in the best interests of all parties, and that clarity would allow the international investment community to see that India is looking to resolve these retrospective tax cases as quickly as possible.
In that context, we understand that there is to be a meeting of an inter-ministerial group comprising of law, external affairs and finance, to provide a response to our arbitration notice. So we look forward to receiving an update from that, and we will of course provide you with updates as and when matters progress.
Turning to Senegal, we've received government agreement for an extensive evaluation plan that will seek to access currently estimated full block potential of gross mean risked resource in excess of 1b barrels. Our drilling campaign is scheduled to commence in October of this year with the Ocean Athena and will comprise of up to six wells. Three of those wells are firm, and Richard will provide more detail on them later in the presentation, and three are contingent.
Our core aim within the program will be to prove up the commerciality of the SNE-1 discovery. In addition, we'll shortly commence an extensive 3D seismic survey acquisition that will help us to further define the full potential of this acreage.
We remain very excited about the significant value proposition in Senegal and we look forward to providing updates as the program progresses.
With that introduction, I'll now hand over to James to provide an overview on funding.
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James Smith, Cairn Energy PLC - CFO [2]
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Thank you, Simon, and good morning, everyone.
So if we turn to slide 6, first of all, for an update on the Group's funding position and our projected uses of capital. At midyear, cash on the balance sheet was $725m and our $575m reserve based lending bank facility was undrawn and remains undrawn. As we've guided previously, we would expect to draw up to around $300m of that facility to fund the UK development projects, with the bulk of the balance available in the form of letters of credit and performance guarantees and other operational purposes.
Our projected capital expenditure for the forward committed exploration and appraisal program is $170m, with a clear focus on Senegal. And our projected capital expenditure on development projects from midyear this year through to the end of 2017, that's on Catcher and Kraken, is $615m, taking those projects through to free cash flow given that they come on stream in 2017.
So, as you can see, the Group is fully funded to deliver the upcoming appraisal and exploration program focused on Senegal and to take the business through our development projects, ramping up from 2017 to peak net production to Cairn of 22,000 barrels a day and thereafter obviously delivering cash flows to support the future strategy.
Simon has already spoken about India. Clearly, our engagement there continues and continues to be a key priority, given the value of our investment. We're pushing ahead with arbitration under the UK Investment Treaty and we'll update the market in due course, but the important point to note here is that the business plan is fully funded from existing financial resources, regardless of the timing of resolution of that dispute in India.
So, turning to the next slide to give a bit more of a breakdown on the expected capital costs, you can see there on the left-hand chart the focus on Senegal. That $130m represents the 3D seismic acquisition program that will commence shortly, as well as the three well drilling program that will span from Q4 this year and into 2016.
That guidance is a slight increase from the $95m previously guided at the prelim stage, and that reflects an expanded scope of what we aim to achieve, in particular an extensive data acquisition program from the wells, including flow testing and coring, that will maximize the certainty regarding reservoir and resource base, and in particular focus on establishing commerciality of the SNE discovery. Richard will come on to talk about that in more detail.
The bulk of the balance of the E&A program is in northwest Europe and that represents seismic acquisition, pre-drill CapEx on some commitment wells, as well as the Skarfjell predevelopment costs. All of that activity is focused around the core areas we have around the existing discovered resource base in the North Sea.
One point to make about these forecasts, which is that we always give the Norway expenditure net of the tax rebate there and there's obviously an ongoing working capital point around that. You'll see from the accounts that we have in respect of 2014 expenditure and 2015 first-half expenditure a Norwegian tax receivable of $77m.
The right-hand chart there splits out the capital spend on the two key development projects. These numbers are both quoted net of the carries we expect to receive from our partners in both cases, from Dyas in the case of Catcher and EnQuest in the case of Kraken.
One point to note on the guidance here, reconciling again to the prelims. At the prelims we guided outstanding Catcher CapEx net to Cairn of $145m. That move to $180m doesn't reflect any change in the underlying CapEx estimate; it's just that part of the Dyas farmdown there settled as cash rather than carry, so the outstanding carry is slightly reduced because we have cash on the balance sheet.
In terms of the specific phasing of these CapEx forecasts, we anticipate around $125m in the second half of 2015 in respect of the Kraken development, and on Catcher we'll be fully carried for the balance of this year and into 2016.
On the exploration and appraisal program, it's always a little bit more difficult to give firm guidance on the phasing of that, but broadly speaking for the three wells in Senegal that represent the bulk of that it will be one in Q4 and two in 2016 is our expectation.
So on to slide 8, to sum up from a financing strategy and a funding position point of view. We are fully funded to deliver our planned exploration, appraisal and development programs. These will take us through key valuation events in the portfolio: appraisal of the Senegal resource base, cash flow from the UK development projects, as well as selective ongoing early stage exploration portfolio building.
We have purposefully and carefully preserved balance sheet strength and took early action last year to reduce our cost base. And as a result, we're well positioned for the current low oil price environment, even if it continues for some time.
Furthermore, we've actively managed our portfolio to ensure we only invest in capital projects with low oil price breakeven economics, and that is true for our North Sea assets which deliver healthy returns to Cairn even at the current forward curve. It is particularly true for Senegal, where we expect the breakeven oil price for development sanction to be sub $40 a barrel and where we're obviously taking full advantage of the lower industry cost environment that we're currently enjoying. And it will continue to be true as we shape the business going forward, both looking at new opportunities and following on from success in Senegal and elsewhere.
And with that, I'll hand over to Richard to talk about the forthcoming operational program in more detail.
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Richard Heaton, Cairn Energy PLC - Exploration Director [3]
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Thank you, James. Thank you, Simon.
Let's move now to slide 10, the 2015 Senegal program, which is going to be a pretty exciting one. And most of my talk will focus on Senegal, and then towards the end some update on our UK and Norway activity.
So, in Senegal, we operate a large block on behalf of the joint venture partners, together with Petrosen, ConocoPhillips and FAR. It's a large acreage position here and last year, as you know, we made two basin opening discoveries, very important, both FAN-1 and SNE-1.
Since that time, we've been very busy working. We've submitted an extensive evaluation program to the government in May this year, and we've had the agreement of the government subsequently to that program. And that is what is going to kick off very shortly, starting with an extensive 3D seismic acquisition program over the eastern part of our Sangomar block and in the southwestern corner of Rufisque. And that will add to the program of 3D that we have had since we've been in the block, which is very high quality 3D over the discoveries we've made so far.
At our Capital Markets Day earlier this year, we submitted a significant amount of technical information about what we're doing there, and everything I'm going to say today is going to be consistent with that, with some further details on actually what the evaluation program over SNE is going to be.
Essentially, that's one of the largest discoveries, if not the largest discovery made of oil last year, so this is a very good place to be. We will start the program with the seismic, probably in September, and the rig, the Ocean Rig Athena, will begin its activity slightly later than that.
If we move now to slide 11, talks about the full block potential. Then we've got a very good position with both discovered resources, some prospects that are identified on the existing 3D and a position with leads on 2D seismic data which will be converted to 3D with the new program. And if you add those three together, then that's a potential gross mean risked resource potential for the block of something around 1b barrels or more, which is a great position to be.
The additional factor is that many of these are sufficiently close together that one discovery and one hub development can link in a series of other prospects and leads when they come to discoveries, as we hope they will.
We have great source rocks here. We have great reservoirs in the shelf area. We've got ability with the high quality 3D to unlock the potential right across this license. We have a very good long column of hydrocarbons in the FAN discovery, the first discovery, but the reservoir quality there was -- there was less net reservoir, but in the SNE discovery then we had good reservoir quality and quite clean contacts, and I'll go through that on the next slide.
So slide 12 sums up the SNE discovery. We have 32 API sweet crude with a gas cap over that, 100 meters of gross gas column and 100 meters of gross oil column, with good quality reservoirs there, high porosity. We've got very clearly defined contacts between the gas and the oil and the oil and the water, and that is very unusual to be able to collect that all in one well. We're quite fortunate in that perspective. And the structural trap here ties down where we believe many of the boundaries on the discovery are.
Having said that, it is an extensive discovery, as I'll come on to demonstrate, and the large aerial extent means that it's an extensive appraisal program we're about to embark on.
If we move to the next slide, this is the first of the appraisal wells. This is a map showing where the SNE-1 discovery well was. The red line represents the gas/oil contact and the green line the oil/water contact at one of the reservoir levels.
You can see that we intercepted gas over oil in the SNE-1 well on this map. The first appraisal location will be very much in the center of the field, where we expect the maximum height of closure of this structural trap. So this should give us the maximum gas, the maximum oil column through the reservoirs.
The importance here is that it will allow us to gather the most information about all the reservoirs and we will have an extensive coring program here of at least three cores. We will have an extensive logging program, which will allow us to characterize those rocks and match them against the logs and the cores. And we will then have an extensive testing program at the end of the well to test both the reservoirs at the base, which are more blocky sands, and also the reservoirs higher up, potentially where they are more heterolithic, thinner bedded.
The importance is that we've got a very high data gathering content. It's very frontend loaded in this program, to ensure that as we go on through the development that we've got the information that we need.
So the second well will be SNE-3, and if we turn to the next page that shows where that's located. It's in the south of the field at this level in the map. And here we will intercept the upper part of the reservoir within the oil column and we'll have an extensive coring program here again, probably three or more cores. And subsequently, if we get the right kind of reservoir quality, there will be testing here of the oil within the thinner reservoirs in the upper part of the field.
Together, these first two wells clearly going to cover a significant increase in data in the field, and the importance of gathering all this information early on is that it will give us the confidence both in the shape of the field in terms of its overall size. You see that line, the green line there, probably over 100 square kilometers in area; it's quite a significant field.
If we move to the next slide, this is the third appraisal location and that is very much to the north of the field. Now, this particular well I'll come on to describe a little bit more later, because actually this is an exploration well primarily to the Bellatrix Prospect, but we've now found that the Bellatrix Prospect overlies the northern end of the SNE field on the latest 3D processing, which is very convenient. So we can manage to get more bangs for our buck in this particular well.
This will define the northern end of the field, allow us to characterize the reservoirs there. We'll have an extensive logging program here. At the moment there isn't a firm coring program here or a firm testing program. Obviously, results will depend a little bit on how the first two wells also go, so we have some flexibility here. The key is that this is a well that will be drilled to gather both exploration and development information.
If we go back now to look at the whole block situation, the program we have submitted to the government not just looks at the SNE discovery, which is clearly the focus to make sure that we gather information there to confirm commerciality and to move us towards development, but we also have, as I talked earlier, a very extensive list of prospects and leads in the surrounding area. Particularly things like Bellatrix that I'll discuss in a moment is very closely positioned and can easily be developed within a hub.
But we have an extensive prospect inventory, which is a gross mean resource of about 380m barrels already identified and a string of leads covered in yellow on this map which the 3D seismic we are hoping some, if all, will be converted to prospects too. And the gross mean number there for those is probably around 330m. So together with the 330m barrels proven and probable in the SNE field, that's how we get to a block wide volume.
So there's a lot of remapping going on at the moment. We have significantly de-risked a lot of the prospects and leads that we saw before we drilled. We always liked this acreage because it has multiple plays in it. We have tested two of the four plays in each of the two wells that we've drilled. There are additional plays that we're starting to recognize here, perhaps as many as seven or eight in the license, and hopefully our exploration program over the next while will start to de-risk those.
And the first one now, moving to the next slide, is the Bellatrix Prospect. This overlies SNE. It has shallower reservoirs, younger reservoirs; no wells have penetrated these reservoirs yet. It's interesting and has seismic anomalies associated with it which it's difficult to see how those arise, given the situation we're in here, without them being quite likely to be oil and gas, so this is very interesting.
We are overlying the oil and gas of the SNE field, so we expect to find oil and gas here. Question is what is the proportion. But as mentioned before, this can be tied into the SNE field when that gets developed.
If we move on now to where we're going to development, on slide 18, the whole point of the evaluation program is to confirm the volumes, ensure that those are above the level that we expect for commerciality. It will take as the information integrating the information between the cores, the extensive logs and the test data, to give us an idea of how many wells it's going to take to produce this field and give us a good idea on the costs.
This is a -- we have a 330m barrel field in this depth of water, about 1,100 meters. There's a number of fields around the world, including in West Africa, where developments such as this have gone ahead. Most are FPSO production systems. And so there's a good deal of cost and technical data that can be used to benchmark the discoveries and developments in these kinds of fields.
We expect the plateau rate for the field to be somewhere in the 50,000 to 100,000 barrels a day, just from SNE alone, and obviously we can tie in other fields.
It does take time to pull this together, so our evaluation plan takes into account that a two to four year period is quite usual to enable such developments to proceed, and probably a further three to five years before first oil. And we're well aligned with partners and government in trying to move that forward in that kind of timescale.
That completes the discussion on Senegal. Move briefly now, a few slides on the UK and Norway. We've been very busy here. This is the other part of our balanced portfolio. Partners are Premier in Catcher, EnQuest in Kraken fields. Very busy with the developments, and both those companies reporting later this week so much of the detail here will be given over the next few days.
But essentially, the Catcher project remains on budget, scheduled for first oil in 2017. We started the drilling of the top holes in the reservoirs July this year, so the rig's on contract and working well. The fabrication of the FPSO hull and topsides ongoing in the Far East, and also we have started work also in the North Sea installing some of the subsea equipment, as shown on the pictures here.
So this is a major project for us. It's certainly a major project for Premier, and obviously heading towards target oil as on 2017.
In Kraken, also in the North Sea, operated by EnQuest, again remains on target and on budget, and again we have begun drilling this year, this summer. That's going well. The top holes have been completed in the first two drill centers and we've begun drilling the first through the reservoir there. That's all going on target as well, and hopefully get more detail from EnQuest on their results presentation tomorrow.
In addition, on the final slide of my presentation to the developments, we also of course built a considerable exploration position in the UK and Norway, mostly around our discoveries and development projects. We're also looking to expand that position. We have been awarded further licenses earlier this year in the Norwegian round. We'll be looking to potentially put some further applications forward in the APA round and the 23rd round, where we've been looking at some of the Barents area this year.
So that's an interesting building position there. It does represent the other side of our portfolio to the West African position. And in addition to these, of course, as Simon's mentioned, we do continue to look at a whole range of new venture and new business opportunities to continue our balanced portfolio.
With that, I'll hand back to Simon.
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Simon Thomson, Cairn Energy PLC - Chief Executive [4]
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Thank you, Richard. Just moving on to the final slide in closing, Cairn therefore remains fully funded to deliver all of its strategic objectives through to the commencement of sustainable cash flow in 2017. We continue to focus on a balanced portfolio, and that's with an appropriate allocation of capital and equity exposure to assets with attractive commercial terms. We believe that provides the best platform for sustainable value growth.
We also, as Richard mentioned, continue to actively assess new ventures within the context of that balanced offering. So that's both as regards additions to our pipeline of exploration opportunities and also cash flow generating assets. And the current oil price environment potentially provides additional opportunities in this respect.
And as you can tell, we're very excited about the upcoming program in Senegal that we believe can add significant value for shareholders by confirming the commerciality of the SNE-1 discovery and also proving up additional resource on the acreage.
Thank you. That concludes the presentation and I'd now like to hand back to the operator for questions.
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Questions and Answers
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Operator [1]
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Alex Topouzoglou, Exane BNP Paribas.
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Alex Topouzoglou, Exane BNP Paribas - Analyst [2]
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Morning, guys, and thanks for taking my questions. On Senegal, we've seen ConocoPhillips take a step back from international and deep water exploration. They canceled the Ensco drillship. So clearly the follow-up campaign will be dependent on the result for the three firm wells, but in the meantime have you noticed any change in attitude from your partners over a follow-up campaign in Senegal?
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Simon Thomson, Cairn Energy PLC - Chief Executive [3]
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No. Sorry. Do you want me to take that or have you got another one?
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Alex Topouzoglou, Exane BNP Paribas - Analyst [4]
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We may as well. We can do them one by one. That's fine.
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Simon Thomson, Cairn Energy PLC - Chief Executive [5]
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Okay. Yes. The answer is no, absolutely not. We've had -- and I'm in close communication with Conoco throughout the team levels right up to the highest levels of the organization, and there is absolute commitment to this project and to proving up the value in Senegal. I think, so not just for us and for FAR but also for Conoco, this represents a material value opportunity. So we're all pushing forward together on this.
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Alex Topouzoglou, Exane BNP Paribas - Analyst [6]
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Great. Thanks. On India, if you could give us a little extra color on your views on the proposed Cairn India and Vedanta merger, potentially whether you're interested in having a stake in a diversified resources company or comfortable share in the Vedanta debt burden and so on.
And then also, if you could provide us with an update on the timelines and so on with regard to India arbitration, please. Thanks.
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Simon Thomson, Cairn Energy PLC - Chief Executive [7]
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Okay. So maybe I'll just answer the first part of your question and hand over to James. Look, the answer is it's premature for us to comment. Obviously, as we've said, we'll look at this proposed merger with a view to voting in a way that's in the best interests of our shareholders. The circular hasn't yet been issued and voting doesn't happen until the end of the year, but rest assured we'll be looking, from our perspective, is this in the best interests of our shareholders when we do come to vote.
But with that, I'll hand over to James on the arbitration.
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James Smith, Cairn Energy PLC - CFO [8]
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Morning. On the arbitration which we launched under -- well, under the treaty we launched a notice of dispute in March, which basically initiates the process. And as we mentioned at the time, there is a period under the treaty for good faith negotiations to try and reach a settlement, and that's what we've been doing with the government, to try and reach an agreement over recent months.
You will have seen recently that we have moved to appoint our arbitration panel member now. So the way it works is that each party, so us and the government of India, appoints one arbitration member panel -- member to the panel, and then those two between them appoint the chairman. And so we've kicked off that process by appointing ours and inviting India to do the same.
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Alex Topouzoglou, Exane BNP Paribas - Analyst [9]
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Okay. Great. Thank you very much.
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Operator [10]
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Stephane Foucaud, FirstEnergy Capital.
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Stephane Foucaud, FirstEnergy - Analyst [11]
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Morning, guys. I've got two questions. The first is more around balance sheet part, James. With the recent movement in oil price and [the pumps hits] the latest RBL -- the bank look at the RBL, how much do you think you can draw on the RBL, given the current context and given the movements on the forward curve?
And second question. What sort of Brent price assumption do you use internally when you look at acquisition or particularly Kraken and Catcher? I understand you look at a low Brent price, but perhaps -- I'm sure you're using a higher oil price for investment decision. Thank you.
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James Smith, Cairn Energy PLC - CFO [12]
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Yes. Thanks for those. On the first one, in terms of the bank facility, as I've mentioned in the presentation, it's the same position as we were back in March, which is we expect to draw up to $300m from that facility. At inception back in 2014, the anticipation was that we would draw up to $400m, with the balance of $175m available as letters of credit and so on.
That $400m has reduced to $300m as a result of two things. One is the farmdown of Catcher, so obviously there's a lower resource base underlying the facility now because we've reduced our stake. And the other is obviously a reduction in the bank's forecast oil prices that they use for projecting cash flows.
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Stephane Foucaud, FirstEnergy - Analyst [13]
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Thank you. And on the Brent price assumption?
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James Smith, Cairn Energy PLC - CFO [14]
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Well, I think in the current environment, as you say, the focus for us is very much on breakeven prices. So we have planning cases in line with many of our peers that anticipate after a period in line with the forward curve, a recovery of the oil price, and that remains our practice for impairment testing and longer-term planning. But ultimately, when we're looking at every project now it's all about the breakeven price, and we really look for something around the $50 mark there. And as I said, in terms of where we're exploring and appraising, it's lower than that.
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Stephane Foucaud, FirstEnergy - Analyst [15]
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Thank you.
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Operator [16]
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Anish Kapadia, TPH.
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Anish Kapadia, Tudor Pickering Holt - Analyst [17]
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Yes. I have three questions, please. Just firstly on Catcher, one of your partners, MOL, suggested there were some issues in terms of the FPSO and suggesting that first production would be delayed from the middle of 2017 to towards the end with that, even maybe somewhat at risk. I'm just wondering if you could just run through some of the issues that are going on with the FPSO over there and how confident you are on that and the 2017 startup date, given all the other problems we've seen with other similar projects in the North Sea.
The second question is looking forward to 2018, after you've got Catcher and Kraken on stream, just wondering if you could give some idea of the free cash flow that you expect from Catcher and Kraken in 2018 in, say, a $50 oil price world.
And finally, I'm wondering if you can just give an update on what's happening on Skarfjell. Thank you.
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Simon Thomson, Cairn Energy PLC - Chief Executive [18]
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Yes. So I'll answer the first bit on your comment on MOL. Yes, we saw that commentary. It relates to the fabrication of the FPSO hull, and there have been some issues. I'm sure that you'll ask this of the operator and they'll confirm, but the operator has put in place mitigating actions to safeguard the sail away date.
So from our perspective, and obviously we've been in conversation with the operator on this, and communication, the project remains on track and on budget. So they've taken mitigating actions to ensure that it doesn't result in any delay.
But I think your next question was James.
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James Smith, Cairn Energy PLC - CFO [19]
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On free cash flow, yes. I think we tend not to give cash flow projections, but I guess there is a relatively simple calculation. So if we're producing at peak 22,500 barrels a day, which would be roughly where we are in 2018, the all-in OpEx costs including FPSO lease costs and so on across the two projects weighted average to us is $34 a barrel.
So, if you take that production level, multiply it by your oil price assumption and take off that OpEx, it will give you a good idea of operating cash flow. There's no tax to be paid in the first several years of production, because obviously we've generated a significant amount of shelter.
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Richard Heaton, Cairn Energy PLC - Exploration Director [20]
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And the final question I think was on Skarfjell. There is an area development planning process going on there, because Skarfjell is just one of a number of discoveries made in the region, none of which on its own is optimally going to lead to a standalone development but together they can. That process is in its relatively early stages, but will move probably towards a concept select position sometime during 2016, is the expectation at the moment.
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Anish Kapadia, Tudor Pickering Holt - Analyst [21]
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Great. Thanks very much.
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Operator [22]
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Dan Ekstein, UBS.
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Dan Ekstein, UBS - Analyst [23]
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Thank you. Morning, everyone. Couple of questions on the appraisal program in Senegal. In terms of the coring and the testing, what would represent a P50 result for you on the coring in terms of the sands, permeability, porosity and hydrocarbon saturation?
And then, on the testing, what's your base case in terms of flow rates and/or PI on that?
And then a second question also on the appraisal program. Are any of the three contingent wells for next year going to have anything to do with the FAN discovery?
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Richard Heaton, Cairn Energy PLC - Exploration Director [24]
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Okay. Let me take the last question first. We have a number of scenarios, as you can imagine, with such an extensive area and many different prospects, leads, and indeed two discoveries. So there are quite a number of options available to us for the second set of wells, if you think of it that way.
We haven't reached a final decision yet. Clearly, there is work ongoing still in terms of reprocessing of the seismic data and inversion, which is focusing on the deeper water FAN plays, and there are multiple reservoir levels there that we penetrated within the FAN well. There are also prospects to the south of that that intersect similar reservoir levels, but also different ones.
We need to look at the whole of that together and tie that in with the latest seismic data, look at what we then think of the volumes and the risks associated with that, in order to make sure that we can place a well in the most optimum position to test that sort of play again, to appraise that.
So no decision has been made firmly on that yet. Of course, it is one of the considerations. It is within the plan. But there isn't a fixed set of wells that we're looking at. There's a rather large number of them at the moment and we'll make sure we choose the optimum ones for those.
Looking at the actual appraisal program in terms of the coring, the idea will be to gather as much information about the various different reservoir levels as we can, and of course it's critical to gather that core information. We will give ourselves multiple chances by focusing on the first wells first. So if we get very, very good results out of the first two wells, then potentially, so long as the result in the third well, for instance, is largely along with predictions, we may not need to gather any there, but it will depend. If we get less than a certain amount, then obviously that will mean that we would want to try and core in subsequent wells as well.
Until we actually see the results and exactly what that means, it would be foolhardy to give a particular precise number of how much we need. That really is down to results. But we have a view of what represents a good result here. We know that the advantage in having a lot of core to begin with really helps with making sure that you optimize the number of wells and the sort of wells in any future development.
Similarly, for the test results, we have very different sorts of reservoirs there. So we anticipate different kinds of results coming out of those different reservoirs. Their connectivity as well as their productivity is important. It will take more than these three wells to answer all of those questions.
As pointed out I think in a slide, in the third well we intend to put some gauges there, so that we can site a well later in the program as one of the possible contingent wells in order to conduct how the wells connect across; sort of interference testing. There's a large range of possible scenarios there. The core data and the logs and the test data from the first couple of wells will give us a very good idea about how to conduct the next set of wells.
To actually give hard numbers at the moment on what we expect from those would probably not be helpful. I think that we've said that the first well had 24% porosity in the main oil sands there. If it remains at that level, that's excellent reservoir quality. The productivity will come from the testing.
------------------------------
Dan Ekstein, UBS - Analyst [25]
------------------------------
Okay. Thank you.
------------------------------
Operator [26]
------------------------------
David Mirzai, Societe Generale.
------------------------------
David Mirzai, Societe Generale - Analyst [27]
------------------------------
Hi. Morning. A couple of quick questions from me. First, on potential for consolidation in the industry, you did point towards cash flow generative assets having potential to add to the business model, especially with your tax losses in the UK and production still two years away. What kind of market are you seeing in UK assets, and how has that evolved from six months ago, 12 months ago, when a deal could have been done?
And just secondly, in terms again of the Senegalese development, you've obviously benchmarked across a wide range of projects and also in terms of years, I'd imagine. Again, how have you seen the cost profile for new projects evolve over those years in the projects you've been benchmarking to, and what type of eventuality do you see for your own project? Do you think that rig costs can go lower? Are you still waiting to see some costs come down in the subsea, or things like FPSO from the yards? What have you seen in your benchmarking compared to what you're seeing in today's market? Thanks.
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [28]
------------------------------
I think I'll let James answer the second part. I think in relation to the first part of your question, first of all, just to clarify in relation to cash flow generating opportunities, from our perspective they're not necessarily limited to the North Sea. And in terms of our assessment from a new venture basis, it's something that at the end of the day would be attractive to us from a value perspective wherever it's situated, although obviously, as you point out, there are some synergies for us in relation to our current position in the North Sea, tax losses and so on.
In the North Sea particularly, it's interesting. It remains a pretty active market. I would say it remains actually pretty competitive in relation to those assets that industry and private equity view as attractive from the point of view of returns. Quite often that's in relation to front end, either production that's about to come on or newly commissioned production opportunities. And obviously, as you all know, there are some packages which perhaps involve later life assets which maybe aren't moving in the same way.
So I think it still remains -- notwithstanding the current price impact of lower prices, still remains a very competitive market, and the trick is to access in one way or another, whether through distressed situations or otherwise, the particular asset without attached liabilities that can provide us what we need. And I think we've always said that we would like to smooth out our cash flow profile and bring forward some cash flow. So, yes, we continue to actively assess that as the market remains active and the market for the right kind of asset remains pretty competitive.
James, do you want to answer the other?
------------------------------
James Smith, Cairn Energy PLC - CFO [29]
------------------------------
Yes. In terms of -- well, I suppose the first thing to say is obviously it feels like a good time to be drilling -- appraisal drilling in Senegal. The costs of doing so compared to our first exploration wells there are significantly reduced.
In terms of the broader cost environment, thinking about taking it right though to development phase, it's always a difficult one with long-term planning, because it's partly relative to what your long-term oil price planning case is, and we tend to run a number of scenarios. I think if we were planning it as of today, then the cost environment would be at least 30% below where it was last year. And that's a combination of deep water drilling having fallen by 40% or 50% in terms of rig costs, and other service costs having fallen by at least 20%, so on balance around about a third.
That said, we run a number of scenarios. So we run a -- as we showed back in the Capital Markets Day, if you assume a recovery to long-term $90 oil price and a cost environment as it existed in the middle of last year before prices started to fall, then we pointed to an unlevered IRR for the project of 35%. But equally, if you run at the other end of the parameter, a long-term $50 oil price case and a modest cost reduction of, say, 20%, then we're still in the 20s in terms of IRRs.
And clearly costs have fallen more than 20%. They've fallen by 30% or 40%, or -- well, 30% or perhaps more, if the oil price stays at $50 or below. And that would take project IRRs back up into the high 20s or 30s. So, actually, the relative fall in costs to oil prices keeps our project IRRs in the same relatively narrow bracket, but both have been very volatile so it's a challenging one.
------------------------------
David Mirzai, Societe Generale - Analyst [30]
------------------------------
No, certainly. And I imagine, given the cost reductions you've already outlined, if we were to have a -- it's called the lower for longer $50 a barrel environment, you would expect some things or some areas which have been sheltered so far to also have to come down in costs. And I am thinking specifically, you haven't seen a lot of the FPSO cost reductions in the market as yet, as people are currently finishing off their oil contracts, but certainly that would be something you could optimize further.
------------------------------
James Smith, Cairn Energy PLC - CFO [31]
------------------------------
Yes. As you say, the longer-term contracts and construction projects, obviously there's a longer lag on those. But certainly, if we're thinking about projects sanctioned in 2018 or beyond, and the oil price has remained lower for that much longer, then we definitely would be expecting to see the impact. I agree.
------------------------------
David Mirzai, Societe Generale - Analyst [32]
------------------------------
Brilliant. Thanks, James.
------------------------------
James Smith, Cairn Energy PLC - CFO [33]
------------------------------
Thank you.
------------------------------
Operator [34]
------------------------------
Sanjeev Bahl, Numis Securities.
------------------------------
Sanjeev Bahl, Numis Securities - Analyst [35]
------------------------------
Good morning. Thanks for taking my questions. I've got two questions. Firstly, I just wanted to see if you could quantify the current UK tax loss position. You can actually see that in your results announcements today.
And secondly, on SNE, your current 2C resource base, 330m barrels, I'm just wondering if you could split that between the deeper blocky sands that you see and the higher thinner bedded sands. That would be very useful. Thanks.
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [36]
------------------------------
Okay. I'll let Richard go first on the SNE question.
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [37]
------------------------------
Thanks, Sanjeev. Essentially, we haven't given a figure out on how those are subdivided. Clearly, there's a number of ways that you can calculate the resource range within the field. We've had a number of people look at that independently, as well as ourselves. And effectively, the ranges that we have given, from a 1C of 150m or so all the way to the 3C figure of 670m, that is replicated virtually irrespective of how you do the figures.
Obviously, we've made some more sophisticated models now and we're looking to back up those models with the well results, where you can start to run some dynamic modeling on productivity. Those obviously fall within the ranges as well. But until such time as we've got more data to actually formally change or release new figures, would not be the most prudent thing at the moment.
We're comfortable, really, with the range that we have. We think that captures both the variability in the lower reservoir proportion and the upper reservoir proportions quite reasonably. Probably the biggest factor affecting us is really just the ultimate shape of the envelope. So the gross rock volume is the first thing that we're aiming to reduce the uncertainties of with these wells, and of course the second bit the actual reservoir qualities themselves across what is quite a large area.
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [38]
------------------------------
And tax losses, James?
------------------------------
James Smith, Cairn Energy PLC - CFO [39]
------------------------------
Yes. On the tax losses, the accounting treatment of presenting tax losses is a little bit complicated, because you have to allocate them across the portfolio, so I sympathize with it being difficult to extract. But the straightforward number is that we have ring-fenced North Sea losses of $470m. So, those are corporate losses, if you like, that have been through acquisition and spend. And then, in addition to that, over the life of the fields we'll build up capital allowances of GBP490m across Catcher and Kraken, so that relates to the small field and heavy oilfield allowances.
------------------------------
Sanjeev Bahl, Numis Securities - Analyst [40]
------------------------------
Very useful. Thanks.
------------------------------
Operator [41]
------------------------------
Rafal Gutaj, Bank of America Merrill Lynch.
------------------------------
Rafal Gutaj, BofA Merrill Lynch - Analyst [42]
------------------------------
Thanks. Morning, everyone. Two questions from me, please. So firstly, James, could you give us a bit more of a defined saving breakdown of both the $170m E&A spend between the second half of this year and the first half of 2016?
And then, moving on from that, likely to be quite a few moving parts, but some more defined phasing of the $615m you think about on Kraken and Catcher, based on your discussions with partners?
And then secondly, Richard, just on your expectation of the exploration element of Bellatrix, can you give us a breakdown of what you're thinking in terms of G costs and what are the primary risks there? Thanks very much.
------------------------------
James Smith, Cairn Energy PLC - CFO [43]
------------------------------
Yes. So, in terms of the phasing of spend, I would say -- I'll give you an indication. I'd say it's a preliminary indication, because obviously phasing -- operational phasing does tend to move around a bit, as does the incurring of CapEx for accounting reasons.
So of the $170m, $130m is Senegal and the seismic will be -- a relatively small portion of that is the seismic which will be acquired this year, and then basically we expect it to be one well in Q4 and two wells in the first half of next year. So, just roughly speaking, a one-third/two-thirds split is probably reasonable for that $130m. And then the balance of the other $40m is probably roughly a half/half split between the second half of this year and 2016.
Sorry not to be more specific, but -- which is partly why we give guidance for the committed forward program, because activity, particularly in non-operated licenses, does move around through the budgeting cycle. But that's probably a fair indication.
And in terms of the development capital, we haven't given year-by-year phasing for that. Of the -- so I've said Kraken we expect to be $125m for the second half of this year. I would say the remainder of that is roughly evenly split over 2016 and 2017. And then, on Catcher, we'll be carried through this year and well into next year, so the Catcher numbers will be over the, say, second half of 2016 and 2017.
------------------------------
Rafal Gutaj, BofA Merrill Lynch - Analyst [44]
------------------------------
Okay. Great. That's really helpful. Thanks.
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [45]
------------------------------
Okay. Just moving on to the Bellatrix Prospect, I'm not sure I caught all of your question, but I think in terms of the risking on that prospect, nobody has drilled through these particular reservoir levels as yet. You can see a little bit from the pictures on the presentation that in fact this is an erosional remnant. It's been called before a buried hill.
Essentially, there isn't any knowledge of what these reservoirs are absolutely like, and that probably is the largest risk here. We do have seismic anomalies in them which are quite difficult to explain, and of course they do sit directly above the SNE field. So it's reservoir quality and what does that mean for how that might produce if there are hydrocarbons in there is probably the largest risk.
------------------------------
Rafal Gutaj, BofA Merrill Lynch - Analyst [46]
------------------------------
Great. And do you have a G cost number in mind on that exploration site?
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [47]
------------------------------
What do you --?
------------------------------
Rafal Gutaj, BofA Merrill Lynch - Analyst [48]
------------------------------
A geological chance of success that you base your estimate on?
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [49]
------------------------------
Yes. We've said that the chance of success is about 80%, previously. I think if you looked at the Capital Markets Day presentation, that's in there.
------------------------------
Rafal Gutaj, BofA Merrill Lynch - Analyst [50]
------------------------------
Okay. Great. Thanks.
------------------------------
Operator [51]
------------------------------
Jamie Maddock, Morgan Stanley.
------------------------------
Jamie Maddock, Morgan Stanley - Analyst [52]
------------------------------
Thank you. Morning, everybody. How many wells do you think you'll need to drill to get to the ability to define SNE as being commercial discovery?
And in tandem with that, I guess, to what level are you willing to run your cash or your net cash, assuming you've drawn your RBL down to?
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [53]
------------------------------
Thanks, Jamie. We haven't yet come up with a final figure of how many wells it's likely to be. Obviously, our interest is in making sure by frontloading our appraisal program to reduce that to the fewest number of wells that we can. However, as you'll probably appreciate, the number will actually depend upon the results of the wells themselves, so that it's quite a complex and an unknown problem.
It will be more than the three penetrations that we have placed in the firm wells, as you can see. We're fortunate that the Bellatrix exploration well can also reach an SNE appraisal location all within one vertical hole, so that's a bit of a gain for us. So it is really all about efficiency of appraisal and the results.
Clearly, the better the results that we get, both from the reservoir quality, from the ties of the core to the logs, if that becomes quite simple, if the productivity from the test results is positive, then it will need less appraisal wells. And the more complicated and variable the results that we get out, then more.
But it would be -- again, it probably isn't prudent to give a specific number at the moment, only that we will be very focused, as the partnership is bound to be, on making sure that that is the fewest possible to get ourselves first of all over a commercially viable number, and then to make sure that we believe that the most efficient development scheme can be put in place. Obviously, it is a pretty large field so getting the number of wells right is a factor that will play heavily on what a cost of development will be.
------------------------------
Jamie Maddock, Morgan Stanley - Analyst [54]
------------------------------
Okay. And then on to the extent, I guess, where you would run your net cash position down to, or if you take into consideration the debt you have accessible to -- assuming, I guess, we're looking to the point at where you have first production of the North Sea in 2017, how much liquidity would you want to retain on the balance sheet?
------------------------------
James Smith, Cairn Energy PLC - CFO [55]
------------------------------
Well, I think there are a number of checks to that, Jamie. One is obviously with the debt facility our lenders are very keen to, as you would imagine, ensure that the business is sufficiently funded through to delivering free cash flow. And they run all sorts of sensitivities in a lower oil price environment and assuming operational delays and so on, to ensure that we continue to be so. So that's a healthy check in its own right.
But obviously, as a management team and a board, you have a policy of maintaining a -- there are a number of tests we apply, but percentages of expenditure outstanding and minimum buffer thresholds to keep us funded through to delivering free cash flow from the projects under all reasonable scenarios, and that's what we'll do. But as you can see from simply adding up the sources of funding available to us now and the committed capital program, there is some headroom to follow on from success and that's where we are.
------------------------------
Jamie Maddock, Morgan Stanley - Analyst [56]
------------------------------
Okay. Thank you. No further questions.
------------------------------
Operator [57]
------------------------------
Nathan Piper, RBC Capital Markets.
------------------------------
Nathan Piper, RBC Capital Markets - Analyst [58]
------------------------------
Thanks. I think my first -- I'll try again here. So first, two questions. First of all, on India again, I know you've given a bit of an update on the near-term plans, but if the Indian government doesn't want to in good faith come to an agreement, how long could that arbitration process take to actually come to a conclusion?
And then secondly, haven't you completed the prestack depth migration on the SNE discovery? And if you have, have you found out that the structure is bigger or flatter and therefore larger than you've previously indicated?
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [59]
------------------------------
On the first one, Nathan, yes, I think obviously we've launched our treaty claim and that has timelines attached to it in terms of timelines for appointment of an arbitrator on behalf of the Indian government in the event that they don't move forward with an appointment themselves.
As to how long will an arbitration take, it's difficult to give guidance. I think we've indicated previously that looking at a full arbitration process could be a minimum of around about 18 months. It could be slightly longer than that. It just depends how quickly you can move forward with your submissions and so on. Obviously, from our perspective, as you might imagine, we are ready to go with all of that.
But, Richard, the other --
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [60]
------------------------------
Yes. Hi, Nathan. The PSDM processing is -- we've never quite completed this, but it's certainly led us to have a much firmer idea of what the shape of the field is likely to be. It's played a part, obviously, in helping us locate these wells such that we can make sure that we get the most information out of them.
Overall, it probably has broadened and flattened the structure, as we imagined it would. Until such time as we complete the final processing that we haven't completely rerun numbers on that, it will have some impact, probably still at the middle level, probably falls still within the range at the 2C level quite similar to where we are at the moment in most models, so we haven't completely updated things as yet.
------------------------------
Nathan Piper, RBC Capital Markets - Analyst [61]
------------------------------
Okay. Thanks. Just back on the arbitration, Simon, I know you're trying to go after it in good faith and everything else, but through a number of legal processes in the oil and gas space the Indian government has proven to be slower rather than faster. So I guess are you -- well, how do you assess your chances of completing this quicker versus drawing it out as long as possible, which has historically been the Indian approach to other disputes in the oil and gas space?
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [62]
------------------------------
Well, Nathan, it's difficult to second guess what the government's going to do, obviously. I think as we previously indicated, there's three broad avenues that we've been pursuing. One is the direct engagement to try and get an early resolution, the second is obviously the arbitration proceedings which have been launched, and the third is an appeal to the tax office directly, which is also ongoing.
I think from our perspective we've been through the process of arbitrations before in India and achieved resolution on those, so we are prepared for that, if we need to go down the arbitration route. The chances of any other solution will depend on the Indian government reverting to us. And as I mentioned, we are awaiting their feedback on the arbitration in particular from the inter-ministerial group, which we understand is going to be meeting any time soon.
So it's difficult to give you a particular date. As I said, we're moving as fast as we can. We think clarity in a solution, whichever route gives a solution, would be in the best interests of all parties, not just us, and we continue to push that.
------------------------------
Nathan Piper, RBC Capital Markets - Analyst [63]
------------------------------
Fair enough. Thank you.
------------------------------
Operator [64]
------------------------------
James Hosie, Barclays.
------------------------------
James Hosie, Barclays - Analyst [65]
------------------------------
Good morning, guys. Just a couple of questions from me. Firstly, on your reserve based lending facility, could we take your comments about drawing down up to $300m as that being the amount currently available under the RBL? And can you just remind us when the next redetermination of the facility is occurring?
And then just on your North Sea development, you mentioned 2018 for that peak net production rate of 22,500 barrels. How long do you expect it to stay at that rate? Thank you.
------------------------------
James Smith, Cairn Energy PLC - CFO [66]
------------------------------
Yes. On the RBL, that's right. That's the current expectations of what we'll draw, and that reflects the oil price having been reduced by the banks, or the oil price projections having been reduced by the banks in the last redetermination. The next one will be at the end of September.
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [67]
------------------------------
Then coming on to the fields, so a couple of years I think is probably expected range of the peak. Obviously, it will depend a little bit on exact phasing of how things build up and when each of the fields precisely comes on as to how the shape of that curve is going to be.
------------------------------
James Hosie, Barclays - Analyst [68]
------------------------------
Okay. And that assumption of a couple of years, that's based on the currently booked reserves, not assuming any additions to that?
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [69]
------------------------------
Yes, essentially.
------------------------------
James Hosie, Barclays - Analyst [70]
------------------------------
Okay. Thank you.
------------------------------
Operator [71]
------------------------------
Ritesh Gaggar, GPM (sic).
------------------------------
Ritesh Gaggar, GMP Securities - Analyst [72]
------------------------------
Hi. Good morning. Last year your drilling in Senegal had rig issues which resulted in basically a lot of CapEx overruns. Can you please provide whether you have inbuilt any contingency or what level, if contingency is factored in your guidance for the upcoming campaign?
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [73]
------------------------------
Yes. Let me -- I'll let James just talk about numbers, but just to preface that, obviously our selection of a rig in relation to this campaign, one, could draw on a wider pool because of the amount of rig availability that there is at the minute as a result of the downturn. That's one of the advantages that we talked about. But two, it's very important for us to select a rig that has been very active recently.
This is the rig -- the Ocean Rig Athena, seventh generation dual activity, that's been drilling in Angola on behalf of the Conoco partnership. So from our perspective we're very focused on the up time records of that rig, which are extremely good, and we're also extremely impressed by the way it's been operated. So that's the preface, that we've been very focused on ensuring that we get the best possible operating equipment for this campaign.
But James, you've obviously got numbers.
------------------------------
James Smith, Cairn Energy PLC - CFO [74]
------------------------------
Yes. Well, I suppose one other point to make is that the particular challenges we had last year were on the FAN well, the first well, which is in the deeper water. The well -- the SNE well we drilled on the shelf was actually within budget and I think slightly under the projected drilling time, and that's obviously where the activity is focused over the next six or nine months.
So we have more comfort. And obviously these are appraisal wells, so we know more what we're going into. So we have more comfort in terms of the timing of the wells than we did in a pure exploration phase, obviously. But yes, that $130m number includes a reasonable contingency estimate.
------------------------------
Ritesh Gaggar, GMP Securities - Analyst [75]
------------------------------
Right. Thank you. Just one more question, regarding the three contingent wells that might be in your calendar in 2016. When should we expect an update on that? In terms of you and your partners would rather wait for the first appraisal well result from SNE-2 before committing for three more wells, or we could hear sooner, in September, when your meeting is held for your partner -- with your partners (inaudible)?
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [76]
------------------------------
Yes. Look, I think we'll start planning that process in Q4 of this year. You're right; there will be some interlinking in terms of the well results, of course, in terms of contingent program, but we're going to be liaising with partners from Q4 onwards. And the other important point is that this isn't a three contingent options, all three wells together. It's a one plus one plus one in the program, to give us as much flexibility as possible in that regard.
------------------------------
Ritesh Gaggar, GMP Securities - Analyst [77]
------------------------------
Thank you so much.
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [78]
------------------------------
Thanks.
------------------------------
Operator [79]
------------------------------
James Thompson, JPMorgan.
------------------------------
James Thompson, JPMorgan - Analyst [80]
------------------------------
Hi. Good morning, gents. Just a couple of quick questions on Senegal. Do the three firm wells and 3D seismic fulfill all of the commitments that you have under the terms of this evaluation plan you submitted to the government, or should we expect further commitments to come, 2016, 2017, 2018?
And secondly, on the SNE appraisal wells, are these going to be plugged and abandoned or are you going to be able to keep those for reentry at a later date, either as future producers, potentially, or just to monitor any future testing you do?
And just away from Senegal, I prefer to think in calendar years; could you give us an insight into what the H2 2016 E&A capital budget looks like at the moment?
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [81]
------------------------------
Richard, do you want to go first on Senegal?
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [82]
------------------------------
Yes. On Senegal, I think the -- can you just repeat the first of your questions?
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [83]
------------------------------
Well, it's in relation to the -- first question, yes, was in relation to the evaluation program, whether the three were the commitments. The answer to that is actually, what the government are agreeing to is a full evaluation program and that's what the joint venture are committing to. But the commitment in terms of firm is just that. So it's the three firm wells and the 3D seismic. We will then take a view as a joint venture, including the government, as Petra said, as to what is the best program of wells going beyond that, but the commitment is these first three wells and 3D seismic.
------------------------------
James Thompson, JPMorgan - Analyst [84]
------------------------------
Okay. So you submit an evaluation program you think will be sufficient to get to first oil, and that will be adjusted based on the results of these commitment wells?
------------------------------
Simon Thomson, Cairn Energy PLC - Chief Executive [85]
------------------------------
No. Richard.
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [86]
------------------------------
No. Essentially, it's a step-by-step process, because obviously we've frontend loaded the program to make sure that we gather as much as we can with the first ones. That will then inform, first of all, the one plus one plus one of the contingent wells that we have already identified as likely, and we've contracted the rig in order to do that.
But the plan that we submitted foresees a wider evaluation of the whole license, obviously, out a number of years in front. And clearly, dependent upon the results of the seismic, dependent upon the results of the first few wells and then the subsequent wells, that has the ability to expand considerably. And there is nothing committed other than the intent to make sure that we do the best technical evaluation of the whole license.
That's what it's focused on, and it's focused on obviously making sure that at each stage that is agreed, both with partners and very importantly the government, that that is the right thing to be doing. That's what we have been encouraged to do as a partnership as well, and that's what we'll follow through.
------------------------------
James Thompson, JPMorgan - Analyst [87]
------------------------------
Okay.
------------------------------
James Smith, Cairn Energy PLC - CFO [88]
------------------------------
And then, on the E&A spend -- sorry, is that -- did you have a follow-up on that question?
------------------------------
James Thompson, JPMorgan - Analyst [89]
------------------------------
Well, just in terms of the appraisal wells you're drilling. Are these going to be completed as producers or are you going to P&A them?
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [90]
------------------------------
The likelihood is that we will be leaving gauges down in some of those wells, to enable us to do subsequent interference testing. We will therefore probably suspend them. But essentially it will depend upon how the development program is actually finally finalized whether they have any role in future. Most fields you'll find not, because potentially you might want to run the majority of wells as being, for instance, horizontal or highly angled wells, but there's no firm plans to introduce these as producers at the moment.
------------------------------
James Thompson, JPMorgan - Analyst [91]
------------------------------
Okay. Very clear. Thanks.
------------------------------
James Smith, Cairn Energy PLC - CFO [92]
------------------------------
And on the rest of the E&A program, that $170m number represents the entire currently planned E&A program, which predominantly will be over the balance of this year and the first half of next year. There is nothing currently planned beyond that. I guess the only significant capital item that's not in that forecast is Spanish Point in Ireland, which might take place next year.
------------------------------
James Thompson, JPMorgan - Analyst [93]
------------------------------
Okay. Fine. So I guess you're looking at less than $50m in the second half of 2016?
------------------------------
James Smith, Cairn Energy PLC - CFO [94]
------------------------------
Well, as I said, that $170m represents everything that's currently planned over this year and next year. The only, I suppose, committed capital item on which phasing is uncertain beyond that is Spanish Point, yes.
------------------------------
James Thompson, JPMorgan - Analyst [95]
------------------------------
Sure. Okay. Thanks.
------------------------------
Operator [96]
------------------------------
Brendan Warn, BMO Capital Markets.
------------------------------
Brendan Warn, BMO Capital Markets - Analyst [97]
------------------------------
Yes. Good morning, gentlemen. Thanks again for a chance to ask some questions. Sorry to labor on about the appraisal program for Senegal, but it just shows the lack of other discoveries we've got to focus on in the E&P sector.
I guess, just if I refer back to your Capital Markets slide pack, which was quite comprehensive, in slide 29 -- I appreciate you might not have a copy of it there with you, but you talked about six variable attributes, couple of which are compartmentalization and flow assurance. I just want to clarify, out of the appraisal wells you are drilling and you've committed to, just what tests will de-risk compartmentalization and flow assurance.
Whether -- so you also talked about DSTs or drill stem testing by the end of this year, on slide 38, and whether they're seen as set up today or you're committing to do drill stem tests, or whether you think you don't need it at the moment?
And can you just talk about the risk of the oil/water contact? Obviously, you've only got one well in this discovery thus far. Just what are the risks around not being certain where the oil/water contact is, and certainly for the southern flank test?
------------------------------
Richard Heaton, Cairn Energy PLC - Exploration Director [98]
------------------------------
I think the -- I'll take the last point first. In the first well, as I said in the presentation, we were perhaps fortunate to intercept both contacts very, very clearly within reservoir section. It's not always that your discovery well gets all that information to you. And the pressure tests that we ran, the MDT tests there, were very, very clear in identifying those contacts. That tends to suggest that the connectivity, certainly within geological timescale there, is very good.
We can, using the seismic data, both the pre-drill [drilling] and now the PSDM data, tie in those to the seismic attributes that we see. The extent that the appraisal wells will reconfirm that, hopefully. We certainly have the contacts as being something that at the moment we are pretty confident are likely to be field wide.
What they don't tell you, of course, is just how variable the reservoir is going to be across what is aerially a pretty extensive structure. But the seismic data does give us some indications that over that area at different levels, and we have broken the reservoir into a number of levels for purposes of, if you like, capturing what the variability is going to be.
Again, both the coring and the logging and the testing will all help us to calibrate that seismic data and use that as a model approach to make sure our reservoir models follow through.
Now, we can already be pretty sophisticated in breaking it into those different layers and characterizing the internal character within it. The seismic responses can be tuned to give us that information. But actually typing that to hard data, which really only is core and logs and tests together, that's what we'll do.
The rig is already set up with a test -- high quality test kit on it. Therefore it's reasonably efficient to be able to run test programs here. We will hopefully, if things go to plan at the moment, be testing in the first well, and that should be within this year if things go to schedule at the moment.
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Brendan Warn, BMO Capital Markets - Analyst [99]
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Okay. So just to clarify, that's, when you say set up for testing, set up for flow testing, flow assurance? And what sort of duration test runs do you think you'll be undertaking?
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Richard Heaton, Cairn Energy PLC - Exploration Director [100]
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Well, we've allowed at the moment in the first well there'll be a number of tests. The planning case is up to about a month's worth of testing in the first well, so it's a significant program. Of course, that isn't the interference testing, which will be the subject of potentially the contingent wells further on. We'll be putting gauges in the first wells to enable that to continue through, let's say, the second phase of the appraisal.
So we'll get single point productivity out this time and then, depending upon those results, that will dictate to us where we should conduct the interference testing, because obviously you want the maximum benefit from that. You can't really efficiently predict that just at the moment.
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Brendan Warn, BMO Capital Markets - Analyst [101]
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Okay. Ideal. Thank you.
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Operator [102]
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Charlie Sharp, Canaccord.
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Charlie Sharp, Canaccord - Analyst [103]
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Thank you very much. I'm sure you're glad that I'm the last question today.
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Simon Thomson, Cairn Energy PLC - Chief Executive [104]
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Depends what you're going to ask.
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Charlie Sharp, Canaccord - Analyst [105]
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And not in three parts, either; just the one question. And sorry to get back to the RBL. I think you mentioned in one answer that the next redetermination was the end of September. If you were to use, or the banks were to use, oil prices that we have today for that, what sort of shrinkage would you expect in the $575m?
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James Smith, Cairn Energy PLC - CFO [106]
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Well, as I mentioned, as a result of -- so the starting point when we put the facility in place in the middle of last year was that we expected to draw around $400m to fund development CapEx in the North Sea, with $175m designed as being the need for letters of credit during drilling campaigns and so on.
That $400m in March this year reduced to around about $300m expected total drawings over the development period, as a result of a reduction in long-term oil price forecasts and the fact that we farmed down a third of our interest in Catcher. So there's a reduction in the underlying reserve base in the debt facility and a reduction in the long-term price deck. So we're now in a price deck that's in the low to mid 60s, or low 60s initially and then mid 60s long term, over our production period.
If that reduced further, in line with where the forward curve is literally today, then that $300m would reduce a little bit more, but it wouldn't significantly impact our funding ability. As we project forward to 2017 on the base case, we probably will draw on the debt facility because that's the efficient thing to do, but in reality we rely on it relatively little to take us through the development phase on those projects, given the cash we've got on the balance sheet.
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Charlie Sharp, Canaccord - Analyst [107]
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So, just to be clear, a redetermination that reduced the headline number would not affect your statement that you're fully funded?
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James Smith, Cairn Energy PLC - CFO [108]
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Well, I think reasonable scenarios are -- as I said, we've already had a redetermination into the lower oil price environment with the banks. If that were -- under all reasonably pessimistic scenarios, if that were to reduce further, yes, it doesn't affect our statement.
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Charlie Sharp, Canaccord - Analyst [109]
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Okay. So even though the oil price assumption may be $10 below the -- I guess you said mid-60s or around $60, there should be no impact on funding?
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James Smith, Cairn Energy PLC - CFO [110]
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I guess what I'd say is, as you can imagine, particularly in this environment, we don't just speak to our bankers once every six months to see what their view is. It's a pretty ongoing dialogue. And so I think, based on that ongoing dialogue, we're comfortable that the statement we're making today remains true and remains true under reasonable scenarios, yes.
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Charlie Sharp, Canaccord - Analyst [111]
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That's what I wanted to get to. Thank you very much.
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Simon Thomson, Cairn Energy PLC - Chief Executive [112]
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Okay. I think that's all the questions we've gone through. Thanks very much, everybody, for listening in, and we look forward to coming back to you with updates on Senegal. So, thanks a lot. Bye.
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