Energy XXI (Bermuda) Limited (EXXI)
Barclay's CEO Energy Conference
September 6, 2012, 2:25 p.m. ET
John Daniel Schiller – Chairman, CEO
We’d like to start our next presentation. I’m pleased to welcome to our conference, Energy XXI. With us from the company today for the presentation, we have John Schiller, Energy XXI’s Chairman/CEO, and I’ll turn it over to John.
John Daniel Schiller – Chairman, CEO
Thanks, Jeff, and good afternoon everyone. Thanks to Barclays for having us here. I’ll just tell you a little bit about what we’ve got going on today. It’s been a pretty busy schedule, a lot of things going on forward. Real quick, if you didn’t catch the press release yesterday, operationally, everything was fine from the hurricane, minimum damage; boat landings and things like that. We’re in a process today of ramping up all of our production. We’re actually – we were a little worried it was going to take longer but one of the gas plants is letting us bypass them. So we’re going to be ramping up. We should be 100% production over the weekend and go about our business there.
Where we are today as a company as a company, market capital impress, $3 billion. Last quarter we made over 47 barrels equivalent a day, 68% of that was oil. Our new reserve number, 120 million barrels of reserves that we announce are in the year-end 6/30 and we continue to go up in a percent oil there.
We’ve got a nice acreage position and the beauty of it is it’s held by production, so a lot of our exploration we choose to do when we’re ready, we don’t have guns to our head in terms of lease expiration.
We operate five of the eleven largest oil fields. I can’t say enough how important this is. It’s what distinguishes us from the other companies that we compete against. Big oil fields get bigger, that’s the bottom line. I want to show you a lot of that as we go through today, in terms of the things we’re doing and how these fields continue to get bigger. You can see we’re predominately oil, especially around the Mississippi river, where most of our production is located.
So, how do we get there? We start with acquisitions. We think we were successful in acquiring a lot of things at the right price. We were opportunistic. A couple of the deals happened where people were stressed out by storms. One of them was [inaudible] was involved, one of them was something that we already had all the operations and somebody [inaudible] 50%, so we kind of had to capture the seller there. And all of those things led up to the Exxon deal, which was our biggest acquisition by far, and one that really jump-started the exploitation. We were doing a good job on the field we had, but the field we had, we were coming behind other independents who had gotten those fields from majors, and we were still having big impacts on our ultimate recovery. Now, with that gone, we’re coming directly behind a major. You’ll start seeing results in the things we do.
This is a result of that acquisition. We ended up with the position that you see here with regards to large oil fields. The two names you’ll see the most up there, us and Chevron. You’ll notice Apache, they make more oil than us, but in terms of having interest in large fields, they’ve only got one of the top 15, and we think that’s a very big part of what we do.
The second part that’s important is technical people, and I can’t iterate enough for you that you can’t play in the Gulf of Mexico with average technical staff. You have to have people that know what they’re doing. Our staff has been doing it a lot of years. Most of them have spent their entire time in the Gulf of Mexico, the Gulf Coast, and the reason for that is your mistakes are much more costly than they are on shore, and so you’ve got to have people that know what they’re doing there.
One other quick thing, when we talk about Gulf of Mexico, we still run into a lot of people that ask you want the average client is the Gulf of Mexico. The answer’s going to be 35 to 40%. And that was true for some of the predecessor companies, and the reason for that was they were highly gas, they had a lot of normal pressure gas wells that you see on a decline curve, and when the water hits on a gas well, there’s not a lot you can do. Your well’s going to go off very quickly. We, on the other hand, have 70% oil, so our wells look much more like the green curve there, which is, we produce at a flat rate. When the water hits, we start going on a decline, and typically you see a hyperbolic where as long as we’re moving fluid, we continue to move oil at a much shallower decline. In fact, when you look at our wells that have been on for more than three years, the average decline there is less than 14%. So, it puts us in a position where, if you look at our production, we’ve got somewhere between 15 to 20% straight decline, if you look at it, and then you add back about 5 to 10% on that just doing our behind pipe re-completions, so literally every year, all we’re really overcoming is about 5 to 10% of decline with our capital program.
This is the Exxon fields, just to give you some sense of size. I mentioned the old fields that we had acquired earlier from other independents. When you look at those fields, in the first six years we’ve had them, we’ve actually increased the ultimate recovery by 7% already. Basically the reserves today are what they were the days we bought them six years ago. We’re going to do the same thing at Exxon. A lot of potential here, a lot of stuff that Exxon simply couldn’t do because they didn’t capture capital, not because they didn’t know the ideas were here, but they’re $20 barrels and in the Exxon machine you can’t capture capital with $20 barrels.
What we show you here is the forecast as it was from [inaudible] acquired. As you can see where we’ve already jumped the production significantly above that forecast, and then the dashed line kind of gives you some sense of what just a 5% increase in EUR would look like. And just 5% on these fields adds $3 billion flux of value in about two-thirds of the amount of oil we currently have on the books.
Another way to look at it is, we had [inaudible] for concentrate on these big fields. We took our five largest reservoirs, we had them do all our oil in place and calculate the recovery factor, and across the board, that thing averaged about 45%. And that’s not a bad recovery number. But here’s the kicker. In the Gulf of Mexico, with strong water drive and good compaction helping you, we’ve documented time and time again 70%+ recovery factors. You can get that. We’ve got multiple examples of it. So if you just look at the oil in place on these five big fields, and you take the recovery to 60%, that’s another 340 million barrels of oil that we can get out of existing assets, we already know where it is, we know which reservoirs it’s in. And that’s where we’re going. That’s where the whole next 5% comes from, and it’s a journey that we’ve started on with our first horizontal well.
Horizontal drilling is not new in the Gulf of Mexico. We didn’t necessarily invent it, but we invented the auto track tools to let us do some amazing things back in the mid-90s. A lot of the majors drilled wells, we drilled horizontal wells, during my Burlington days, and then you had $10.00 oil time in 1999, it kind of went away. And then the fields that had the opportunities were sitting in the hands of majors who really quit investing in the Gulf in early 2000 when they started putting all their money into the deep water.
So what you see here is at ST21, these are some of the tight [inaudible], you see how the wells have become hyperbolic. They start flattening out. And more importantly, down below is your water [inaudible]. If you thought a well was going to water out, that thing’s got to go to 100%. You’ll see how they bend over at 95%. This is at ST21, at West Delta, you’re still doing the same thing at about 90% water cuts, and you see wells making over 2 million barrels of oil. Those are the type of things you get in these type fields, and all you’re really doing if you think about it is you’re putting a well at the top of the structure, you’re moving fluids, you’re moving water, and down at the bottom of that structure, your residual oil is working its way down from 25% to 20%, and hopefully as low as 15%, and you’re letting Mother Nature do all the work for you. And that’s kind of what we show you on these pictures.
There’s three different applications. Strong water drives, that’s where we’re starting. Partial water drives, and then pressure to [inaudible] where we need to put some water into the ground. That’ll become the last target that we attack. The first field we chose to do this on was West Delta 73. This is a large, 4,000 acre structure. A lot of wells penetrated it. We drilled four more wells so we could get some sense out of the series of sands, which we now have 30 out of 35 F-40 and F-45 on where the current oil water contacts were, and we’ve now drilled the Big Sky 2, which is our first horizontal well.
Now, horizontal well offshore is a little bit different version than what you’re used to hearing about on the shale plays. We drill a pilot hole. We need to know what that sand looks like in that area, where exactly the top is. So on the left is the original log we drilled, penetrated 23 feet of pay. We back up 1,000 feet, we get going at 90 degrees, we go into the top of the zone and we set pipe, and then we drill out our horizontal section. We drilled 1,000 feet here in about 2 ½ days, and this is the long side. Most of our horizontals will be closer to 500 feet. As you see, we were kind of sitting on a high ridge there, so we wanted to make this one a little longer, and that’s what 1,000 feet of good, clean sand with nice resistivity looks like. And so, you can see we get a 50-fold increase on our [inaudible], probably going to lose some in our vertical [inaudible], so we’ll say we get a fifth of the perm. That still gives you a 10-fold increase in your KH versus a normal vertical well. And then in this field, because Exxon’s already drilled some wells, we know that on average they averaged 800,000 barrels a well versus 350 for the vertical completion. The 15% extra money, you get 2+ times the reserves. We actually think that number’s going to be a lot bigger. What’s factored in here, different from those decline curves I showed you, is that some of these early wells had mechanical issues where we [inaudible] and only made 50 to 100,000 barrels, so you’ve got an average being pulled down by that, but on your good wells you should be +2.
So adding to that, we’ve now, as several of you know, we’ve talked about getting a reservoir match with [inaudible], they’ve got that work completed in the last month, we’ve got assimilation, we’ve got pressure responses that match, and this reservoir’s going to make 72 million barrels of oil if we do nothing to it. If we put eight horizontal wells in at the [inaudible], we’re going to get about 89 million barrels. So that’s a 17 million barrel incremental, right at two man barrels a well, and more importantly, it takes over our recovery factor in this one reservoir to about 70%. That’s the same number we keep seeing time and time again.
So that’s what we’ve got going on. Hopefully we would have had a number for you, but the storm came up, so we’re out there right now getting ready to run a gravel track. We complete these things open hole, with a gravel pack screen, there’s no cracking, there’s none of that, we circulate the gravel in place and we put the well on production.
To talk a little bit about the rest of what we’ve got going on. Four operated rigs and three non-operated wells drilling for us are completing Davy Jones. And then you can see, our capital budget, $700 million for this year. We’re still on tune for that number. [inaudible] that have been with us for a while know that we have targeted about 650. About 50 million of that is kind of creep associated with costs on the, mainly on the rig sides, but I think that’s fairly stable right now. And as you can see the different breakouts, about 15% of our capital is going to go towards exploration, and what I will tell you today is that we continue to find some interesting exploration opportunities and we’re going to probably focus more on oil than gas, so some of the original wells we talked about, such as under Golden Bear and Wombat will probably just move off the schedule and get replaced with some oil upside exploration that we’ve seen on our properties.
This is Main Pass, obviously the poster child for what we do, a field that when we took over had 5,000 barrels a day. We took the production over 20,000 barrels a day in the last month when we brought on the Don Tomas Well. It’s been a really good field for us, another place that we started with modeling from [inaudible], got a good reservoir match told us the field could be a lot bigger, and other modelings proved to be correct. And this kind of gives you a sense of the different logs that we have there. The Don Tomas on the far left, you can see, we called that the eyeball when we drilled it, it was a really big, bright amplitude that sure looked like it was going to be clean sand, then sure enough it loaded up and that well is currently making 4,200 barrels of oil a day. So we’ve had a lot of success out there in that area, and you’ll see us continue to go. It’s an area where amplitudes tend to be very meaningful and predictive of hydrocarbons.
Grand Isle is another field that we went into. You can see some big production jumps as we brought on a couple of big gas wells, but today we’re still double where we were when we bought it, and a lot of good activity going on here. We had the Sunny Well winners was the big gas well, that well produced at 40 [inaudible] a day. It’s now down to about 15, but it’s actually going to exceed what we thought the ultimate recover was when we drilled it. You can see the Pi Well, another series of stacked [inaudible]. Apologize, because the storm has me off on counting but I think we’re, I think Big Sky became our 12th straight [inaudible] well that we drilled on the Exxon [inaudible] without a dry hole, so there’s been pretty good drilling for us. Costello, you can see those stack pays, that’s also a very good well in the field, so this is what we’re doing. We’re going up dip and we’re doing a horizontal well. That’s the key of how we get all this oil out of the ground.
Over in South Tim 54, similar thing, we’ve got the spark plug well that we’re drilling right now. We’ve logged the pay up above the H1, we’re getting ready to set some pipe and drill out into the H3 and expect, based on geology, all the way down that we’re going to see some nice sands full of oil there. Ad you can see, Camshaft is another [inaudible] block where we’re loaded again and we’re [inaudible].
So that’s kind of what we do day in and day out on the exploitation side. I’ll show you a little bit about the ultra-deep and tell you how things are there. Now those, if you remember real quick, when we all went out in the deep water in the late nineties, we were expecting to find younger rock. We basically thought the rocks would look like what you see in lavender on this slide, which is the lower [inaudible] just fell off a rift and were buried way deep. And when we got out in deep water, we started making discoveries in middle and lower Miocene sands, and in 2001 in Neocene, that changed the whole game, and that’s when we came back to the shelf and started re-looking at things and saying, wait a minute, we can get to these deep ejective sands on the shelf at a place where they should have the ability to be productive. Prior to that, we really didn’t thing there were any sand stories with depth on the shelf. So this is our whole ultra-deep layout of where we have the opportunities. The green ones are what we’ve already done. We’ve gone about it in a very strategic sort of way, from shallow pay to deepest pays, and you’ll see that later, but things continue to move along.
Davy Jones, the [inaudible] put out their update yesterday. We still expect to have a float test this month. We’re cleaning out the well bore, that should happen hopefully with one trip, we’ll hit the bottom, we’ll come out, we’ll run a packer, and then go about running our tubing. That’s about a 10-day event once we get to the point of running production tubing until we’re nippled up and ready to flow, so I think that late September is a pretty good date there.
Blackbeard West, we had pipes set right before the storm, so we’re going in there today. Should get a formation test at our [inaudible] and go about drilling, and we are right where we want to be. We’re below the salt well, we’re in the closures, we’re where we have the reflectors on the side. And we’ve got a couple thousand feet left to drill there, so if you remember, this is set up by the Blackbeard East shallow sand that we saw right below the salt, and if successful here, it really sets up a really big play over at Barbosa, which is what you also [inaudible]. Now the key thing in Blackbeard West is it’s more conventional. The [inaudible] are shallower. We can do all this with 20,000 pound equipment, have it all in production within six months and start generating some pretty good cash flow.
Highlander is an on-shore play, as we’ve looked at the play we were able to [inaudible] on-shore, put together a big position through a couple of groups there who own their own [inaudible], so we’re going right up to where the source of the rock is coming from, right in the middle where these big channels were dumping. That well should [inaudible] here in the next month or so and be a barge job.
We put all the ultra-deep together and you look at the total volumes you have 148T is the potential. Our net’s 22. None of this is anywhere on our books right now. A small bit of it is contingent resources. Obviously, we need Davy Jones to flow. That’s the first step in getting a bunch of these reserves booked.
And as I mentioned earlier, we kind of went about this in a systematic approach. We had three strategic areas, the Blackbeard area, the Lafitte area and the Davy Jones, and you can kind of see we ranged everywhere from upper Miocene sands all the way down to lower cretaceous that we saw on Davy Jones 2. That’s a function of where you’re drilling in the Gulf and what depth you can get to the different sands at.
So let’s talk about beyond 2013. Here’s our rig schedule. You can see it’s fairly busy. This doesn’t show everything because we’re still holding back a couple hundred million in the kitty, so there’s some more drilling to be done out here the second half of the year, but we’ll put that on as we start developing. We want to see what our horizontal wells do and where the best application of that additional capital goes.
Our inventory is pretty stout and it continues to get better every time we turn around, we find additional opportunities out here. If you look at just inventory this year, which shows no horizontal well impact, just vertical wells, we get a $75 oil and $3.00 gas. We generate $1.50 PIs, so we make $1.50 back discounted at 10% for every dollar we invest. In my life, [inaudible], so $1.50 is pretty strong at $75 oil and reflects the nature of the big fields. And when I say we find it all the time, we’ve got another well, [inaudible], that we were just looking at last week. It’s the classic deal. Big fields have big reservoirs. It’s a reservoir that’s made 21 million barrels of oil. It’s only made 6 million barrels of water. Exxon more or less quit producing it 10 years ago, and the well that everybody would’ve said watered out, mainly because it did water out, we ran a log in it two months ago and the sand’s full to base with oil now, so what’s happened is, Mother Nature’s been doing for 10 years what we want to do with the horizontal drilling. She’s been charging up the reservoirs, oil’s been moving to the top of the reservoir, displacing the water back down, and we’ve got like a 300 to 400 foot oil column sitting up there, so that’s where we’re going to drill the [inaudible] well. That’ll be a really good well for us. And that stuff, while it’s on the inventory, is nowhere near the inventory, doesn’t have anywhere near the volumes identified with it that we now realize we have there.
All of that leads to what we think is a fairly unique story, which is nice growth with free cash flow. We kind of show you a high and low depending on prices. Obviously, we’re running very close to the top price, and so we’re generating a lot of free cash flow this year and we’ll continue to do that and we’ll put it to work where we think it can do us the best. Probably as good a place as any to talk about M&A. the M&A market has heated up some. There’s a lot of it coming out of the private sector. We continue to, if we can go get our hands on more of the top 20, 25 oil fields, you’ll see us make those moves. If we can acquire properties within our existing infrastructure where we can make synergies work, you’ll see us make those moves.
We’ve always been fairly good on the hedging, aggressive particularly around acquisitions. Our favorite tool around acquisitions is the foot spread, frankly because we can put it on the day after we sign a purchase sell agreement. You don’t have to have the buyers to put the hedges in place, so it’s a good way to project the downside for us, and then as we take over a property, we’ll move the hedges around. We have gone away from swaps, you’ll notice that on here. We don’t feel the need to try and call the perfect price. What we do is price-protect at a downside and give ourselves a lot of room to the upside in case something silly happens with prices.
So, wrapping up early as I usually do, large Gulf of Mexico fields give us significant cash flow. That’s the key. The thing that makes Energy XXI different than most of the companies you see talking to you are the fact that we got these big oil fields with a lot of oil in place, we know where the oil is, it generates a heck of a lot of cash flow. We had 94% of our revenue off 70% of the production, which is the crude, and that’s where we focus our time and effort to get more of it out of the ground. The inventory continues to grow, we don’t need acquisitions to grow the company, we’re going to do that on our own, but we are going to be opportunistic. If there’s an acquisition that we think allows us to apply what we do really well, we’ll grab it. And you get all that, and we got the ultra-deep sitting out here, it’s a big wild card that’s frankly just treated as an option in our sight. So, thanks for listening. Are we doing Q&A?
We have a few minutes for Q&A and there will be a breakout session.
It looks like the XL3 is no longer going to [inaudible] after Davy Jones. Is that now going to Davy Jones #2 and then what are you plans for Golden Bear?
John Daniel Schiller – Chairman, CEO
Well, the XL3, [inaudible] because you heard that from someone or because I told you?
John Daniel Schiller – Chairman, CEO
I think we show it right there, the XL3. We’re still planning on getting unless I’ve missed something. So – but whether we drill with it or do work over, it’s a little bit different this year. We may just do some recompletion depending on the timing like you’re talking about. We may not have as big of window to work, we may not have time to actually drill the well we want to drill with it. So we may do some shifting there. That’s the kind of dynamics we would question right there. You could walk in and tell me that Jim Bob said he’s keeping it and I wouldn’t disagree.
John, you might talk a little bit about deep gas economics in the Gulf of Mexico because everybody we – everybody on shore except for [inaudible] in North Eastern Pennsylvania talks about gas economics not being – not supporting drilling. But you all were a little bit different.
John Daniel Schiller – Chairman, CEO
Yeah. There’s two ways. As far as – let’s just talk about if we go drill some gas within our existing platform’s infrastructure, like [inaudible], you know, it literally costs us 15 and $0.20 an MCF to lift the well. We [inaudible] no [inaudible] tax, no state tax. All we pay is a royalty. So in a $2.80 gas environment like we’re in right now, we’re still printing a lot of cash. The Winner’s well we drilled made 10 BCF, that’s $20 million back on an $8 million investment in six months. So we make a lot of money doing that. The Gulf has always been the low cost producer because of that. The infrastructure’s there, you all have all the extra taxes that the onshore guys have to deal with and you get these high flow rates. So you get a lot of buying by [inaudible]. When you go and look at the Ultra-Deep, a little bit different equation. Obviously, much bigger dollars involved. We’re looking at finding costs probably in the $1.50 to $2.00 range, so at 2.80, it can get skinny, but it’s still going to give you sort of teenage rate of returns, rate of returns in the teens. I think the big picture there is when we start talking as a nation about export and [inaudible], those are the type of fields you want. You want big TCF gas fields in place. You want to be able to sign direct contracts with the countries overseas that need LNG and I think you can sign those contracts today between 4 and $6.00 and everybody would be happy. It delivers them a price they need and it makes us a lot of money. So I think those are the things that happen as you go forward from here with regards to the big [inaudible].
Any other question of John? Well, I think we can move to the breakout room, which is Liberty – I’m sorry, Riverside Ballroom if there are any follow-up questions.