Some relevant parts from the cairn earnings call. Looking great to me.
Q2 2016 Earnings Conference Call
August 16, 2016 04:00 AM ET
Executives
Simon Thompson - Chief Executive Officer
James Smith - Chief Financial Officer
Richard Heaton - Exploration Director
Paul Mayland - Chief Operating Officer
Simon Thompson
Good morning everybody. Welcome to Cairn’s Half-Yearly Results presentation. I’m Simon Thomson, Chief Executive. With me are James Smith, CFO; Richard Heaton, Exploration Director; and Paul Mayland, COO.
So a few words on Senegal where a safe and successful appraisal drilling campaign has confirmed the world class nature of the SNE field. Paul and Richard will come on and talk about the detail, but in summary, we are delighted with what we have proven up thus far, and also with the additional potential that we see, not only in SNE, but also in the surrounding acreage position.
The resource base continues to increase, and today we have announced a significant upgrade in our contingent resource estimates. The SNE 2C STOIIP is in excess of 2.7 billion barrels, and that’s with current gross recoverable resources now standing and revised to at the 1C level 274 million barrels, at the 2C 473, and at the 3C in excess of 900 million barrels. For the sake of comparison at the 2C, as you know the previous guidance was 385 million barrels, so a significant increase.
In addition, we still see in excess of 0.5 billion barrels of risked resource upside, and right now, we are working on the exploration prospectivity to finalize prospects for consideration in the next phase of drilling. Richard will talk about a couple of those exploration prospects in his section of the presentation.
As Paul will outline, development planning is underway. We believe we are well placed to benefit from cost deflation and also project optimization, and that in turn has a very positive knock-on effect to our economics, as James will outline. The third phase of E&A drilling is scheduled to commence at the turn of the year, and again we are benefitting significantly from reduced costs both in respect of rig and also associated services.
So in summary, we see continued delivery of value from Senegal. The combination of reduced costs, increased resources, and also near-term activity that will access in our eyes significant potential upside. So there is a lot still to go in Senegal. James.
James Smith
Thank you, Simon. Good morning everyone. So in the next few slides I will go through the cash flows for the first half, the current funding position, and an update on our future capital investment plans. As you will see, the focus remains very much on capital discipline to continue to ensure that we retain the flexibility to direct investment to the assets where they will deliver the best returns.
For us today, that’s really about two key areas. The first is completion of the Catcher and Kraken projects to deliver sustainable cash flow from next year, and those barrels are with an all-in average production cost of $17 a barrel at plateau.
The second, which we will spend most of our time today talking about, is further de-risking of Senegal, and that’s really an asset that’s delivering on our principle strategic goal as a company which is about material, low cost resource bases within large acreage positions.
Committed as of today exploration and appraisal activity, $55 million, which represents ongoing activity in Senegal, plus relatively low commitments across the rest of the portfolio. And in the next two blocks there represent what we see as being still under currently planning phase, but the expected minimum activity in Senegal in 2017.
So that’s two appraisal wells with one or both of them having a relatively full testing program, and pre-development study work ongoing on the assets, so that totaling around about $80 million.
As Paul and Richard will come on to say, 2017 is going to be a key year for Senegal in terms of moving it towards a development concept decision and submission of a development plan in 2018 and 2019. So clearly, there is the potential for that program in Senegal to expand well beyond those two wells that we are envisaging as being the firm program.
Onto the asset where we are expecting to have the optionality to deliver the most value from the current cost environment, and that’s in Senegal.
This slide provides an update on the development scenario and associated costs for an SNE 2C development. It’s a chart in the same format that you will find back in our Capital Markets Day in May 2015, but with some important revisions to that.
We would previously guided for full development CapEx per barrel of around about $20 based on analogue fields and similar water depths for FPSO developments. But based on the improved contracting environment today, but also importantly our experience of drilling five wells into the reservoir so far, we are updating today that guidance with reductions of 25%, 30%, so we see sub-$15 a barrel all-in development CapEx for a field of the 2C size that we have guided to.
This assumes a leased FPSO development, so you can see the bulk of the CapEx there is really in development drilling and subsea installation. So the good thing about that is that it means that most of that CapEx is back ended towards first oil, which clearly enhances the economics and the financing plan for a development of that type.
Operating costs associated with that development scenario, $8-10 a barrel, and that includes an FPSO leased cost assumption in there. And again on timing, the guidance remains the same. So with the development recommendation in 2018 and FID in 2019, we would expect first oil to be in the window 2021, 2023.
Next slide here sets out of the economic outputs of that development scenario if you like, with NPVs per barrel at the various oil prices, and unlevered project IRRs at those same oil prices. You can see there with the dotted yellow lines, which represent the guidance we gave back in May 2015, that that results in a pretty significant upgrade both in terms of value and project returns from the previous guidance.
And as you can see, pretty healthy returns even at today’s oil prices and we think reaching a threshold 10% return in the low 30s Brent. Clearly these are economics for the 2C standalone development of an SNE field scenario, but as Richard will come on to talk about, the significant resource upside potential in the block, so exploration success near to that field could clearly be developed at relatively low cost as a tieback to the central development.
Finally on SNE economics, this slide here sets out the results of that development plan in the context of breakeven oil prices for other projects globally. It’s taken from the Goldman Sachs study of international upstream projects, which we have screened for development phase projects, and you can see SNE ranks extremely highly on that list in terms of its ability to attract industry capital.
And as Paul will come on to outline in a bit more detail, whilst SNE is normally a deep water development, the operating environment, the geological characteristics and the fiscal terms altogether combine to mean that it actually ranks above many shallow water or shallower water development projects and even some onshore ones in terms of its economic attractiveness.
So in summary, before I hand over to Richard to talk in some more detail, the focus has been very much on capital discipline to make sure that we have an investment strategy that’s very, very focused on assets to deliver returns in a lower oil price environment.
And as a result of that we are very well positioned to deliver the business into cash flow phase next year and to support from the current balance sheet our continued investment in the Senegal asset, whilst in the background continuing to build the portfolio opportunity set in the background.
And on that note I will hand over to Richard.
Richard Heaton
Thanks, James, and good morning everyone. First of all, just a brief reminder of Senegal. Two years ago we still hadn’t made our discoveries in Senegal so we have made a tremendous amount of progress since then; six wells now drilled.
And you will see that essentially the first two wells both were discoveries, they were both the first wells ever drilled in the deep water offshore Senegal and the first two oil discoveries of any size in Senegal as well.
We have focused our attention since nearly wholly on the SNE area, it’s shallower water, the reservoirs are better quality there, and that is really where the bulk of our effort has been to date.
What is new today is that we are announcing an upgrade in the resources that we see in that field and also giving the detailed figures out on very large in-place oil that there is in the field. We have a very large area in the license and I will be talking about the exploration potential there as well.
So the next slide really talks about the results of those wells that we have now drilled. We have had a very successful and safe campaign to appraise the SNE field, we now have five penetrations across that field, roughly sort of nine kilometers in a north south line and about five kilometers from east to west, right in the central portion of the field.
The field during that time, as we have proven with these wells now, has increased in size and at the very top seal the area of the field is over 350 square kilometers. We have across that area now, so far as we can see there is a very consistent 100 meter gross oil column there with a gas cap above it in the centre of the field.
We can see that everywhere we drill those five wells we have good quality reservoirs and better than perhaps one would normally predict in these age of rocks and type of rocks, but it’s very consistent, and shown on here, just one of the reservoir layers in the upper levels of the reservoir.
Right across the field we always find sands, we always find them of good quality, we can actually tie them very accurately on the seismic data, we have new seismic data and we process seismic data now that ties very well across the field.
And we can use the amplitudes from the seismic data as shown on that little map to almost differentiate between where there is gas, where there is oil and water, and some of the internal features of the rocks there.
We have recovered a huge amount of core data, every bit of core that we try to capture we recover back to the surface, we have 600 meters of rock in the laboratories in Aberdeen and elsewhere being analyzed, it allows us to really characterize the reservoirs of the field very, very accurately.
Now that work takes a long time to complete, it’s a huge amount of data, we integrate that with all the log data that we have got from these wells as well. It’s a fabulous database to work with and we are still working through it.
What that means is we are able to confirm a great deal more certainty now about the field, we have got great information that allows us to understand how it’s put together. And essentially as we said and saw in SNE-1 the reservoirs are best at the bottom and then we have lower reservoirs above that, the finer grained and slightly thinner reservoirs above that.
We have got good test results out of both though, the lower reservoirs, 8,000 barrels a day out of one test and in the upper reservoirs 5,000 barrels a day. Those are great test results for anywhere, some of the better ones that you will see along the West African margin.
In the test that flowed 5,000 barrels a day from the upper reservoirs, some slight pressure depletion which shows that the connectivity there is not quite as good as in the lower reservoirs, and that will be a feature of trying to understand that uncertainty when we come to the next phase of appraisal.
So the resource base is hugely improving as we go through, for the first time here giving the figures on where we were at March with the associated in-place oil, the STOIIP, and today’s estimates are independent estimates given by ERC-Equipoise, demonstrating if you like the consistency between our own and an independent auditor’s view.
And we have now got over 2.7 billion barrels in place at the 2C level and a recoverable resource out of that of 473. And you can see it’s a wide range, these are probalistic estimates, this is trying to take into account still the very large variation there is in the field, because we are still really at the relatively early stages, only 18-months after discovery, of trying to piece together what is now a very large field.
But it’s a great story, what we will be doing with the next wells is trying to understand better the connectivity and make a yet more informed decision about how best to develop the field and what sort of field development plans put in place, and Paul will go on to explain some more of that.
Not only is there obviously a good field but we went into this area because if you did find hydrocarbons there is a great upside story here, there is lots of different plays to go for, there is an exploration potential around it, which we can tie back to a main project and working that data now.
Integrating the new well data with the new seismic data and coming up with more detailed exploration prospectivity which we will incorporate into the next drilling plans. Paul will give more detail on the actual drilling plans a little bit but essentially I will just give some details on two of the prospects, one in the shelf area and one in the deeper water area now.
Altogether we estimate there is probably another 500 million barrels of mean risk resource in those prospects to go, so you add that together with almost 500 million barrels in the SNE field and the block potential, still a billion barrels which is the guidance that we have continued to give.
So the Sirius Prospect we have talked about before. This is on the shelf, it’s just to the north of SNE, it’s at the same reservoir levels, we can separate it out at some of the upper reservoirs here within SNE, we see this as relatively low risk, it’s a stacked field as we now know from SNE is the case.
Probably around 80 million barrels, just over 80 million barrels when you consolidate those in the prospect, but a very high chance of success based on what we see in SNE, so a 67% chance of success. This could be a very attractive tie-in prospect.
And if we go to the basin you can see the FAN well in there to the north, that FAN, a very large column of oil, over 500 meters altogether of oil soaked rock, but the reservoir quality in there, it’s quite deeply buried, not so good.
Further to the south, there is a prospect here that we are looking at which is much shallower, we can see the feeder sandstones coming in from the shelf, from the field, SNE field, we do hope that the reservoir quality here might be better.
In just one layer in this prospect we have about 150 million barrels mean prospect resource in here with about a 15% chance of success. It is a stratigraphic prospect, stratigraphic trap, that does work at FAN, it could well work here, again it would make a very attractive tie-in.
Now all this work is still very much ongoing, integrating all the new data from SNE and the new seismic, we haven’t made decisions firmly yet on which wells we will be drilling as part of an exploration program, that is still yet to come.
And at this point I will pass on to Paul to take us through the next stages of the operations.
Paul Mayland
Thanks, Richard. Good morning ladies and gentlemen. As already mentioned, we intend to move to a third phase of drilling offshore Senegal, commencing towards the end of this year, and we aim to build and indeed improve upon the good HSSE performance that we achieved during 2015 and 2016.
The proposed program is anchored around two firm wells, plus multiple one well options and both semisubmersibles and drill ships are under evaluation for what has already proven to be a very sought after contract.
There are a number of objectives to be addressed in this program, including testing certain reservoirs that otherwise have not yet been tested and interference testing between wells, and this was always part of the joint venture’s appraisal strategy reflected by the fact that we have installed pressure monitoring gauges in two of the existing four appraisal wells. And as Richard has also alluded to, exploration opportunities are also likely to form part of the program.
In parallel with the earlier appraisal drilling we have remained conscious of the expected journey through appraisal and development planning and the requirements ultimately for a final investment decision to deliver oil production offshore Senegal. We have completed a highly successful second phase of drilling, primarily focused on the SNE appraisal, and that as Richard has outlined has provided us with an excellent data set.
Further appraisal activity is focused on improving the definition of the project, in particular related to water flood planning of the upper reservoirs which ultimately influences the number of drill centers and their location and the number, location, offset and orientation of production and injection wells to be drilled on the field.
The concept that we have previously outlined, a floating production, storage and offloading vessel with subsea wells remains valid and the 2C resources presented today guides us now to a plateau rate of between 100,000 and 120,000 barrels of oil per day.
I think everyone is familiar from the capital markets day of last year with the timeline shown at the bottom of the page, I think that illustrates the remarkable progress the joint venture has made in only 18-months since discovery and the considerable effort that we will undertake together over the next 18 to 24 months to allow us to submit an exploitation plan in the first half of 2018.
On this slide you can see a diagram which outlines a range of offshore projects versus water depth taking us all the way out on the right hand side to the current technology limit for deep water of around 3,000 meters. SNE obviously sits very comfortably within this window and is classified as a deep water discovery being located in approximately 1,000 to 1,200 meters of water.
Indeed, it is worth noting that the SNE reservoir depths are actually less than the water depth alone in other global ultra-deep water discoveries in the Gulf of Mexico and indeed, close by in Africa.
Also shown on the diagram on the left are our two non-operated UK projects, Catcher and Kraken, and these have given us excellent insight into the service contractors, their performance on the projects and their differentiating characteristics.
They have also allowed us to sharpen our views on contract strategy and models for execution particularly at this interesting time in the industry, which we will inevitably along with our other joint venture partners clearly discuss and seek to apply in Senegal.
So moving onto the next slide in terms of development conceptual engineering we have initiated pre-engineering studies with an established engineering house and we have outlined the initial preliminary reservoir and wells basis of design. We have also installed a MetOcean buoy this summer offshore Senegal to gather further data in respect of optimizing facility design.
And overall we believe this project is very well placed being at the concept select stage to now benefit from project optimization, cost deflation and further standardization. Because although there is some CO2 in the gas stream the reservoir conditions and fluid conditions are otherwise relatively benign and this will allow us to utilize existing standard oilfield equipment, and because of the scope and phasing of the project it is expected that this will be very much on the radar of the usual service providers.
Onto the next slide in terms of conceptual development well planning. In addition to preparing for the next phase of drilling, as illustrated in the photo of our new pipe yard in Dakar, the wells team have been working together with the joint venture completing initial studies in respect of conceptual development wells.
We believe that around 15 to 20 wells will be drilled prior to first oil as part of a multi-year ongoing development drilling campaign which will comprise oil producers, water injectors and gas injectors. Approximately two thirds or so will target the upper reservoirs with the remainder targeting the lower reservoirs.
A variety of well types are being investigated but most are ultimately of a near horizontal or high angle type with lateral sections of around 1500 meters in the reservoir and may or may not include some form of intelligent completion.
On average we believe that the well costs have reduced by around 25% from our previous estimates and this has been carried forward in the economics presented by James earlier. So in summary we are making good progress in terms of commencing another exciting phase of exploration and appraisal drilling anchored around the SNE discovery and we expect to start that campaign and operations before the end of the year.
We believe that this particular project is well-placed to benefit from further optimization, cost deflation and standardization, and we remain on-track to submit an exploitation plan during 2018.
Simon Thompson
Thanks, Richard. So in summary we continue to offer significant growth opportunities within a balanced portfolio. We have got a material and growing resource base in Senegal as you’ve seen and we have got further near-term drilling activity to access upside resource and are benefiting from a lower cost environment.
We have got balance sheet strength and we have got substantial cash flow from near-term production from Kraken and Catcher in 2017. And the company continues to focus on value creation and monetization of success as you see from a familiar diagram on the right, that continues the long-term strategy of creating, adding and ultimately realizing value for shareholders.
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