Energy XXI (Bermuda) Limited (EXXI)
Capital One Southcoast December Energy Conference
December 11, 2013 03:40 PM ET
John Schiller - Chairman and CEO
Richard Tullis - Capital One Southcoast
Richard Tullis - Capital One Southcoast
We’ll get kicked off here with Energy XXI. John Schiller is going to present. John is Chairman and CEO, and he is joined by Stewart Lawrence as well, and we’ll hear a little bit about what John and Energy XXI have going on in the Gulf of Mexico. John?
Thanks. We’re also glad to be here. Good afternoon, everyone. Welcome to the cold south. I’ll tell you a little bit about what we’ve got going on Energy XXI; kind of a round number, $2.2 billion in market cap; production run around 47,000 barrels a day; 64% or 66% oil somewhere in there; a lot of reserves in the ground; 232 million barrels of 2P; talk a little bit about how to get that out of the ground; and 75% of our reserves are oil, as you look at us.
From day one we set this thing up to be able to acquire and exploit mature oilfields. We’ve been very successful with that. The reason there is very straight forward. You will get a lot more oil out of the ground. We’re talking average recovery factors over time of 40% to 45%. And we think with the economics where they are from $80 a barrel likely we’ll start seeing those numbers creep towards 60%, 65% even 70% in some of our better reservoirs where we’ve already seen that.
This gives you a sense of what we’ve done in the last couple of years in reserve growth. We’ve taken our PV-10 under 3P and over $10 billion; a lot of reserves identified in the ground. Again, you look at these big oilfields that we have and they’ve got over 3 billion barrels of oil in place. So we’ve only produced a little bit less than half of that. So you know where the oil is. This is not an exploration target. This is going to get it out of the ground. Some of our big ads came out of the horizontal program over the West Delta and in some reservoir stimulation stays over in South Timbalier and the typical acquisitions in West Delta 30 field study, which is where we’re starting to drill.
Little bit about acquisitions; this shows you how we’ve grown the company over time. We think we’ve bought at the right price. There is a lot of barrels of oil when you’re buying in the Gulf of Mexico, you got to look at what your P&A you picking up are. Among other things and how expensive things are to operate, clearly oil properties are arguably more expensive to operate than gas prices. We deal with a lot more water, so we pump a lot more chemicals to our lifting cost. That said, we’ve been very happy with where we bought and you’ll continue to see us look at that market and we think there will be other opportunities out there.
As a result of all of that, we operate five of the 11 largest fields in the Gulf of Mexico. I would argue that it creates a company you’ve never seen before. Most of these fields have been owned by majors. You never had one independent controlling this many large oilfields. So, it gives us a lot of synergies, gives us a lot of opportunity, it gives us ability to go in there and get what I call the $15 and $20 barrels. And frankly the excellence in the world you can’t get because you can’t capture capital that chase those kinds of returns. And then it’s a total different game for them when they’re looking strictly about how much profit per barrel they make rather than the kind of returns they make.
So, that’s what we do. We were very happy with what we put together. We’ve done it well. We’ve bought about 146 million barrels of oil over-time. Today, when you look at those fields, put the production back-in, there is about 261 million barrels there, sort of an 80% uplift in reserves. I think you’re going to see that number continue to grow on these fields.
The exploitation itself just gives you some sense of our drilling inventory, our schedule, where we’re at. We just picked up our fourth rig over West Delta 30. That rig has spud, the Striker well. We’re actually milling the window to begin to start side track there. So we’re starting to pick up rigs as we go at the end of our fiscal year as you can see on this rig schedule at the bottom there.
Horizontal drilling in Gulf of Mexico, a little bit different animal than what you guys will see from the shale players. And we’ve got all the prime ability we need. For us, it’s more about reducing the pressured drop across our perforations and improving the drainage efficiency in the reservoirs. When you look at a typical vertical completion, our overall acknowledgement in the pool is anywhere from 300 to 500 pounds of pressure drawdown, 500 is sort of a number where we think our gravel pack start cratering. So we’re trying to avoid that number.
That doesn’t sound like that much pressure but at 300 and 500 pounds of delta P, you’re literally jetting fluid into your wellbores. When you turn around to do this horizontal wells, our model so far indicating the nodals [ph] that we have about 10 pounds of pressure drop getting the same amount of fluid or more. And so in that case your fluid is just kind of driven into your wellbore; you’re not creating this pressure differential cone, you are getting a lot better sweep of the reservoirs and that’s really what the play is about.
As we go forward, we’re doing some of this blind right now. We haven’t had a lot of production loss with our rig on top of the world we drilled at West Delta. We are finishing up our last well there and then we will be running some production logs, and I think you will see us make things improve how we go about as these completions occur, enough right now we still are making close to $3 for every dollar we invest in the horizontal well. So they’re doing great as it is. We just think that there will be room for continuous improvement as we understand exactly where our fluids are coming from within those wellbores.
Another thing that is a little bit unique is you are shooting on much smaller targets. You’re trying to typically stay within a 10 foot interval, maybe a 20 foot, 25 foot of oil column. This is just an example of one well recently, where you can see we went out one time. So over 1200 foot of lateral. We stayed in it of over a 1000 feet. So you’re deal steering the whole time and you’re making sure you stay within you sands.
This is what the results of all that is done at West Delta 73. You see a production growth increase tripling. We are now getting prepared in December to bring a second rig out there. It will be another platform rig. And then we’ll have 2 rigs running basically drilling the same reservoir but from a little bit south of where we have been drilling.
So when you look at what we’re seeing to date and what’s working for us, we think we still have over 95 locations out there. Expect that number continue to increase as we get into smaller reservoirs, bypass reservoirs and then pressure depleted reservoirs which we haven’t even started at. We have been sticking mainly with water-drive reservoirs, that don’t need a lot of water injection help.
From exploring side, we tend to take a joint venture approach there, first with our friends at Freeport McMoRan on the ultra-deep. Then we moved in with Chevron on the ultra-deep and then last two ventures with Exxon over Vermilion. We are making the salt play and then also with Apache which will now obviously be filled with an Apache.
So the stuff that is going on out there in the Gulf right now, the things we’ve learned as we drill the deep water and as we drill the ultra-deep, is that salt was doing totally different things than what any of us ever envisioned, particularly over the last 20 years. So you’re seeing this panel back in the 70s when I came out of school, all the way up to as recently as five years ago, all these big salt domes were modeled as big projectile salt domes. We didn’t really understand the fluid mechanics or the flow mechanism that was going on.
We starting re-looking that and re-process it with 3D and in this example you ended up seeing what looks like a tooth with a shallow or halo zone underneath its salt and more importantly for us day 1 was that the salt was much further up dipped than we originally envisioned. So we were able to drill an up dip well. This is where the Onex [ph] plays for us. We got 2 million barrels underground at 48,000 feet and in the course of 18 months and at a cost of about $30 million. So those are the kind of economics you get around salt.
That’s what first opened our eyes up to realizing there was a lot to understand under the salt domes. So when you are look at the typical Gulf of Mexico, where we are showing on the left there, you can see why it was so important in deep water, because we had huge salt features covering everything out there. More so, there were more lateral salts and salt domes, you will see as you move on the shelf it becomes more salt domes. And on the seismic panel we just kind of give you sense of what wide Azimuth seismic does for you in terms of seeing things underneath the salt.
So the wide Azimuth, which for years we would all tell you was way too expensive to shoot any place but in deep water around the world, we are now bringing on the shelf. Chevron did it first over their Bay Marchand, which is the single largest drill in the upper Mexico. Our South Timbalier 21 block, which is in Old Gulf Chevron field was shot as part of that survey. So we are getting that data. We already have the data on Block 21 in itself. And in the next few months we will get the data on the offset block there, which is where our Creek prospect is.
But we’ve already seeing enough to tell you the same thing we saw from 3D process and it is definitely occurring on the WAZ which we’re seeing a much better interface where our actual salt features are, where our up dip limits are. We’re seeing the ability to drill up dip wells that we didn’t think we had and as we go deep, we’re getting a much better image of what the structure looks like down there.
However, on the east side there, is the joint venture that we did with Apache, where we shot over 900 square miles. That data has all been acquired now. We’re in the middle of process and there’d probably still be a year before we have all that data processes and our drilling features on, but this is the area where drilled here. And then to the west of that is some of our main past production that we’re all sort of looking at how do we get it included in that shoot?
On the Exxon Mobil joint venture [indiscernible] in those wells, this was a structure that again was mapped as a vertical structure, ends up being a very tilted salt dome and that’s the play we’re coming up underneath the tilt. That well is drilling for us and I think we will have results for you by the time we do our next earnings call.
Apache joint venture, this is one when we have released date on with the Heron well. We found over a 100 feet of oil. Basically we found oil down to 16,500 feet, which was also important for us. So a little bit of deeper depth that we thought we might be able to maintain oil.
One of the things we saw here surprisingly is very much like you see in the deepwater, even just being under the salt overhang, our temperatures were less than we thought and that allowed us to take that oil window even deeper than what we originally envisioned on it. We’ll be coming back here, we’re T&A on that well and then we’ll be coming back here in a month or two with another rig to drilling an Asia well on that discovery.
Over on ultra-deep front, we continue to drill there and de-risk it. We got a series of plays there. They go from -- they’re all underneath the salt well but you hit pacing the shallows 19,000 feet and all the way down to 30,000 feet. We are on a daily jumps two now starting that completion just kind of show you the depth of things below the salt well.
We have started the completion of Davy Jones 2. That’s probably a three to four month process and then we’ll see that we flow out of that. That will be a completion down in the cretaceous in Tuscaloosa different sands than what we perforated in Davy Jones 1 as you can tell from this slide. Delivery results have been a key part of that. We continue to drive value by the reserve adds that you’ve seen and this kind of shows you the last year-on-year as we restart PDP by over 50% and corresponding values there.
The developments tend to be focused -- our capital is focused on development. You’ll notice out of $675 million, $330 million is going to development wells. This year we have fairly big number on facility. That’s because we’re putting a new platform at West Delta 73, which will go into summer and will start being a place that we put rigs working for the following years and get our production out of there. So we’re kind of front running that. Similar thing on the core exploration, that’s basically the salt play as I showed you with Apache and Exxon. Again once we get all that stuff out there, next year, you’ll start seeing development capital. You’ll start to see the production results from there.
Very much oil oriented. We are really not doing anything gas other than associated gas and then I think you’ll see a very nice results as we’ve seen already for the first half of our year. Currently as I mentioned three operated wells, drilling development then our one exploration well, total four wells that are up and running. Then our non-operated wells you see, they’re also. Discount-wise we continue to trade at a pretty significant value through our net asset value. We look at where the reserves are 2P, 3P et cetera.
I think the thing that’s always important, remember we talked about Gulf of Mexico as all of our reserves in the 3P category have to be in reservoirs that we’ve already penetrated and proven productive. So there is no all set pop locks in here. There is no amplitude for includes that main pass for every amplitude we driven, we’ve drilled has been productive. None of those are even in our 3Ps. The 3Ps are just basically down dip and up dip reserves to production we’ve already discovered in the same reservoirs.
So we feel like there is a lot of value to be added. We’re going to continue to get that value out of the ground for you. Momentum is building. The horizontal oil wells are doing a really good job. We’ve been getting one well after another now. We think we found the key there which is not to be super aggressive. We don’t try and drill the top two feet of the reservoirs anymore. So we’re still hitting 85% and 90% oil out of the ground. We’ll leave that last 10% for another day.
And we’re not drilling as aggressively when we go up dip against salt. Our faults are giving ourselves more room. At West Delta 30 you will see that, difference between West Delta 30, we actually have a lot of salt penetration point. So we have a pretty good sense for where the salt is. We are not drilling up dip development wells down dip depth and nothing up dip.
So I think you’ll see that is why we’re going to continue to have one well after another in this program. The exploration we think is world-class. I will promise you one of us is going to find a 100 million barrel field underneath the salt. That’s just the way it is. When you look at the – the opportunities are out there and the size of the field you’re drilling below, where you’ve already produced 300, 400, and 500 million barrels of oil and you’re going down, you’re seeing sands that have never been penetrated in a trapping position. And then again our pre reserve is 6.1 billion.
And so with that I think I’ll wrap it and close. And thank you all for being here today.
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