Energy XXI (Bermuda) Limited (EXXI)
Barclays CEO Energy Conference
September 11, 2013 3:45 PM ET
John Schiller - Chairman and CEO
Let's get started with our next presentation. My pleasure to welcome Energy XXI to our energy conference. Speaking on behalf of the company is John Schiller, the company's Chairman and CEO. With that I will turn it over to John.
Good afternoon everyone, glad you're here. Thanks to our friends at Barclays for having us, always a great way to start off the fall. Being in New York and hot weather.
I will tell you a little bit about what we got going on in Energy XXI, this is a quick snapshot of the company. Production right around 47,000 barrels a day. You can see the market cap, about $2.3 billion and the inside ownership are just over 6%. You can see where we have been increasing reserves, 179 million barrels of proved, and we will go into that in a lot more detail in a couple of pages; and we got a nice acreage position, the key point to that acreage position, majority of (inaudible) production, which means it does not go anywhere, gives us an opportunity with a lot of exploration prospects to where we will drill as we get to them as economics won't.
From the day we formed the company in October 2005, what was an acquire and exploit strategy, we focused on material oilfields. We have been very successful in acquiring that, you will see as we go through. From there, our goal was to increase value by 20%. We have done a really good job with that also, and as we put those things together, we wanted to add to exploration branch, in and around those fields, and you will see some of that today, and then the bottom line to deliver the results that we promised.
This is our reserve growth page, just to give you some sense of what we did over the last year. 50% increase to the past year, 179 million barrels, with a PV of 6.1 billion. The total 3P reserves are now 310 million barrels of oil. A year ago at our investor conference, we started talking about the next 5%, and what we were talking about was getting the 5% incremental recovery, taking recoveries from 45% to 50%.
We truly believe that a lot of these big reservoirs underneath these large oilfields, that recovery factor is in the 65% to 75% range or possible. They have been documented. Our friends at CoreLab concur with that. So you are going to see us keep pushing, put the capital in the ground, get our drilling up and continue to get the reserves.
You see this kind of bottom breakout chart here, where those big pieces came from, over at West Delta, 73. It was about 29 million barrels of oil. That was all around the horizontal drilling we did, both existing producing wells and PUD locations. Over at South Tim 54, we added about 15 million barrels, most of that was well performance on the west side of the field, where we got a very large reservoir, the HP3 sand. That's a sand that we will be drilling additional well into, hopefully here shortly. But the well there continues to make 1,000 barrels a day, and looks like it's going to make 8 million to 10 million -- or 10 million to 12 million barrels of oil, just in one well. It's already (inaudible).
Then further from there, we did acquisitions obviously, added reserves. Our West Delta 30, which we will start drilling this year, we went through a remap, and that's a field that has made 600 million barrels of oil, with reprocessing of 3D and remapping, where we have identified some up-dip locations for about 10 million barrels of oil.
And then the bottom one is Main Pass, which those of you who follow the story know, Main Pass' amplitude driven field; because the way our government wants to identify proved reserves that we can't show continuity in a connected reservoir that's already been proven productive, we can't put the reserves anywhere in the 3P category. So consequently, every well we draw at Main Pass, it's a new amplitude as a reserve bed.
Acquisitions; this is a historical look at what we have done through time. With our margin acquisitions, we are pretty proud of where we have bought. We have tended to buy at the right time, at the right price. Obviously, the Marlin was significant and that put us in the business, so you got the South Tim 21, the ninth largest oilfield in the Gulf of Mexico. From there, the next big deal was Pogo, which bought us to Main Pass area and South Pass fields. Mitsui, where we picked up the non-operated pieces of the Pogo there, and we timed that really right, they wanted to go invest in shale. We were coming off of March of '09, where the world [tried to end], we are able to buy at those prices, properties quite attractively. Then obviously, the Exxon transaction, which is what really put us on the board. There is a lot of large drills to work with.
The end results is what you see on this slide. We operated five of the largest fields in the Gulf of Mexico, in terms of cumulative production. Big fields get bigger, that's the bottom line, there is no other way to explain it. All fields in particular, with waters [drive] is there, it's a friend it's not an enemy. If you move fluids, you will continue to increase recovery, and that's where we build our whole exploitation plan around, with regards to oilfields.
This is just a slide to show you that we do what we talked about. If you look at what we acquired over the years, we have acquired 141 million barrels of oil. Those same fields today have produced 75 million barrels of oil, and our total ultimate recovery is going to be 261 million barrels. So we have added 150 million barrels to the same acquisitions through drilling wells, up-dip wells and increasing recovery, about 80% uplift.
Exploitation, this shows you our drilling schedule for this year. If I was to categorize last year versus this year, I will tell you this is about as safe and simple as it gets. We went in the last year program with a lot of high volume wells. We had four wells, giving ourselves 16,000 barrels day. 12,000 of that was oil. We had several wells in the budget that were going to give us 5,000 or 6,000 barrels a day equivalent from gas wells. This year we go in with the highest producing well and the company making about 2,000 barrels a day, and no well in the budget that will give us more than 1,500 barrels a day. So it's good and solid, no one well is going to derail us from meeting our target.
On the flipside of that, the wells are pretty simple to drill, we have only got a couple of abnormal pressure test if you will and most of those are over in Vermillion, with the salt play.
The horizontal drilling itself in the Gulf of Mexico is a little bit different animal. We started so early, we had to correct a few things. Those are mainly that, how aggressive you want to get with wells.
What we show you on this slide, is what a vertical well typically does, and I don't care how good the perm is, when you put 200, 300 or 400 pounds of drawdown, which is what we typically do on a producing well, we are going to create a cone around that well bore. When we go around these horizontal wells, we are seeing documented drawdowns of less than 10 pounds, to move several thousand barrels of fluid today. So it's a much more common reservoir to produce, you are able to produce oil for longer period of times, and you get a much better sweep efficiency through your reservoir, and that's what works in the Gulf of Mexico; it's not about not having permeability, it's about reducing our pressure drop to the point that we get a lot of oil out of the ground.
This just gives you an example of the tough side of drilling in the Gulf of Mexico horizontally, and that as you are drilling a target about as tall as this room, and you want to stay in it for 1,000 feet. So what happens, is we will be going to airs, we are not as well documented (inaudible), i.e. outside West Delta 73. You encounter some dips in sands you do not expect to. And you can see on this example that we drilled 1,200 for the lateral, we stayed in sands for 1,000 foot of it, but you are literally sitting there, watching that well for 48 and 72 hours of the time, to make sure you do that.
The end result, we get a right to particular West Delta 73, which you start seeing here, where we have been ramping up our horizontal well production. We got six wells on now, making over 3,500 barrels oil a day from those wells, that continue to -- that's net. They continue to perform very well, and obviously, this is going to be a big part of our program for this year.
In West Delta 73, we will end up running two rigs by the middle of the year. We will also be adding a new production platform, and that's a $65 million facility of development there. 12 slots, they we will be able to move 15,000 barrels of oil a day and a lot of water. So that's what we need to do to keep developing this field.
We have got 95 locations identified across the company. This is still early on. We are in a phase where we are drilling 100% clean oil. I think 18 to 24 months from now, as we move on, you will start seeing down on structure some, and put wells that are in what something, what we would consider the swept zone already, where the end result is 500 to 750 barrel a day well. Moving 3,000 or 4,000 barrels of fluid. The recoveries won't be 1.5 million barrel, but there will still be 500,000 to 600,000 barrels, still be very economical, and still continue to drive down that residual oil and increase your recovery factor.
On the exploration front, we'd like to say, we explore with the right partners. Freeport McMoRan oil and gas in the Ultra Deep, and then Exxon and Apache on our salt play, and then Chevron also on the Ultra Deep. So we got a lot of things going on with a bunch of different partners, all of which have a very good understanding of our business obviously.
One of the things that has gone on to Gulf, and we are going to do our Investor Day on October 22, try to give you a lot more details around this, but one of the things going is the rejuvenation around the salt domes themselves. So in our case, we started reprocessing over the Main Pass 73 area. You can't underestimate the speed of the computers today. The algorithms we are able to use, and then as I go forward from here, we will talk about why it adds an assignment. So Main Pass 73, we reprocess this, and you are going to see on these three panels, the conventional mapping of the salt dome, which is this big projectile volcanic looking thing, versus what it really looks like today, it looks more like a tooth. And these things we have been learning about salt over the last 15 years of drilling in the deepwater well, drilling in the Ultra Deep and doing a lot more sophisticated modeling of what happens with salt.
So in this case at Main Pass, we are able to find up-dip locations. This is where we found the Onyx reservoir, which was a 2 million barrel reservoir, at 4,800 feet, in a field that already made 100 million barrel of oil, it was just sitting there up-dip and over penetrated and over (inaudible) production. Then we have also got the [below salt] test there, and that's kind of what let us up to, hey there is a lot of things that can happen around these old salt domes.
When you look at what's going on in the deep water, industry is averaging about 42% success rate on their wells. A lot of that because of the use of wide azimuth seismic, and what this picture shows you is, the amount of salt covered in the deepwater area, and then you see the salt down along the shales, and you've got a little cut out seismic section. As you see, there is some sense of how the wide azimuth helps you identify the salt, and more importantly what's underneath the salt.
For us, this is what started out on the shelf, Chevron shot the first seismic survey over the Bay Marchand. You see our South Tim 21 field was included in that shoot. We have actually seen that data, and we will show you some of that at our Investor conference. But what I can tell you, that's already let up our up-dip location. We actually have additional drill locations [landfill] where we thought we had drilled everything. All of that because of the sharpness and the definition you get from the main seismic sheets. We are going to extend that -- initially, we are looking to take it in the South Tim 54, which is where we think it will be most helpful; and then we joined into a deal with Apache to the east, over the main pass area, where we have 25% and they have 75% working interest. After the sale, this is going to be a 37.5%, 37.5% (inaudible) Apache and us were 25%.
And what we are doing there, is shooting all new wide azimuth. It's about $150 million shoot. We will do the Apache air, which is about 70% shot so far, and then we will move into our area, which will be 100% us. So where we have Main Pass 73 and 61. This is the area where we are drilling the Heron well with Apache right now, and I will show you something about that, but that's what's going on with the wide azimuth.
With Exxon on the joint venture, which was another playoff, what we were starting to learn about the salt. There, they have a tilted salt dome, a lot of opportunity to the south side, where people thought it had already been drilled and they were nowhere near the structure. That well today, Marlin is about 14,000 feet. We encountered some difficulty running our liner. We had to pull out the hull, the well tried to flow on us, but we will get the liner back in the hull, and go back to drilling there, and once we drill out this line, we will probably make pretty good headway towards TD.
On the Apache side, this shows you what has been going on at Heron. We have already announced 76 fleet there. That well is progressing quite nicely. We will have a lot -- when we TD, we will have a lot of logs running on. I anticipate if things go right, we may be able to talk a little bit about it at our investor conference, but we will just see how that works.
With regards to the ultra deep, we continue to derisk there. We have finished -- we are nearly finished coring with Chevron over the Lineham Creek, where we were coring the Yegua sands. Lomond North continues towards the final TD, with McMoRan operating it. I think we will take the data from there, and you will see us push that play further onshore, learning what we have learned about the Yegua and the Wilcox Sands, and then you also see it coming back and doing a completion of Davy Jones 2, as that becomes available in the Gulf of Mexico.
Let's just kind of remind you that we called the ultra deep play, we probably should call the salt well play. What it's really doing is, is going below the salt well, and that salt well can be a challenge; 19,000 feet, as deep as 26,000 feet, and it's pretty continuous. That's what we see as we go on toward of South Louisiana, some of these opportunities we are going to take advantage of. People drilled into the salt well 30 years ago, [updated] at the end of the world and quit drilling, and they weren't that far from potential pricing (inaudible) structure. So we have got a pretty good control there, as we chase this thing further onshore.
Delivery will be a key part of this; year-over-year reserve growth. We show you where we were last year at 120, this year at 179. We have already talked about where that came from, a large increase in our present value, almost $2 billion, almost all that directly related to the reserve increase. The focus in the capital program this year, as I mentioned, we have taken out wells that we consider to be potential trouble wells for the most part, none of our development wells go under pressure. You are going to see us continue to do things, for instance the [Hawk] well that we are currently drilling at West Delta 73.
There is no power hole there, we have had enough well control that we are going straight into horizontal. So every time we can do that, we are going to say five to 10 days on the drill time. So hopefully, we continue to drill more wells more efficiently, and spend that $660 million where it gets to most production. You can see that it's all directed towards the development, for the most part over 80%. More importantly, most of it all directed, particularly all the development well. So over the year, you are going to see our percent wall continue to decline; and as I mentioned earlier, we got a big facilities project in there, and obviously hedges will continue to pay a formal part for us.
Currently that gives us three operated rigs; the two drilling at West Delta 73 and Main Pass, and then we got the Marlin prospect drilling. We will be picking up a 4-3 here shortly to start West Delta 30 drilling for us, and I think that's sort of the program, three to four rigs as we go through the year.
The hedges continue to be what they are. We usually hedge 75% to 80% of our 4-12 months, that's where we are. We are in the 40% to 50% two years out. Third year out, we are a little lower than where we have normally been, but with the backwardation of the curve quite frankly, we have a hard time (inaudible) hedge much. We are fairly bullish long term. So we have got a number we are looking at. We have gotten closer a couple of times, and we will see if we can put some more hedges on, for the third year out.
The balance sheet remains solid, you are going to see as we will put in the final wrapping right now, and increasing our revolver to be over $1 billion when we agree with that. We will continue to look at what's going on out there in the world, in terms of our bonds, our bond price, and then the potential bond issuances we might be able to do. But I think the main thing is, keep the balance sheet clean like we have it. Have the ability to continue to purchase shares, which you will continue to see us do, and have flexibility around monetizing some of our assets, and bringing in outside money to help us drill some of the other opportunities that we have.
The net asset value calculation, this is what it looks like, what you get from the penalty box. We are going to get out of there. We got a lot of value that we can create. As I have said, keep delivering solid quarters like we have been doing. 47,000 barrels a day is a good number. It's a 10% year-on-year growth, particularly as we generate more oil out of that number, so our cash flow does even better than that. You are going to see us focus on that. As I said, bringing some money in and cleaning up the balance sheet even more, and generating free cash flow off our capital program. Those are the things that work for us, that have worked through the past, and are continuing to work.
So we are in a situation right now, where we are drilling good solid horizontal wells. We are not trying to get aggressive, we are not trying to go too far up-dip, not trying to get every foot out of the sand. We are staying close to the top of the sands, we are not out of the top. We got some great exploration plays going on, on both the ultra deep side and the salt plays that are delivering near term results for us, and our current 1B reserve is over $6 billion, so there is a lot of discount going on there between what we trade at, and where we value that.
And with that, there will be a little Q&A.
Time for questions.
Yes? We are basically sitting where we were back in intercom. We are 14,000 feet. The question was what are we doing at Marlin. We are 14,000 feet. We went in to run our liner there, and the well started flowing on us. So we had to fight it to try and get to the bottom. We couldn't get the liner to the bottom, it was hanging up, as we went into open hole. So we got the well killed, and pulled back out of the hull, laid down the line, and when you're laying down an expandable line, that's a long term process, it's not a day process, more like a four day.
We got all that done, we didn't leave anything in the hole, and now we are going back in the clean [out]. We had test VLPs and all that, which is a slow process, but -- so as we get back to TD, cleaning the mud (inaudible) right, we will run back hull over the line or get the liner set. From there one, it should be fairly quick.
That's kind of what happened. When at Intercom, Heron was doing just the opposite. We were taking kicks, and was losing circulation. Once we got a fix, we have been drilling anywhere from 300 to 500 foot a day, and that's what we kind of (inaudible), and we will get it done quickly. We just got to get through this. This is our last little trouble area.
John, could you talk a little bit about the potential for cost savings that you grow more horizontally in West Delta and other fields?
As I was kind of talking about a little bit, I think the biggest potential there is that you start eliminating more and more palette holes, which saves five to 10 days. What we have been seeing is, now we are drilling like the eighth well and ninth well with the West Delta platform rig, and the guys know what they are doing, they get a little bit more efficient and we start reducing our flat times, that's the biggest area. The drilling rates are really good, it's where we provide things when you run pipe, the whole flat time. So you take too long, and therefore we put a lot of emphasis right now in trying to get the guys on the rigs, some incentive to short net time. So I think you start carving, including the (inaudible) 10 to 12 days off a 40-45 day well, it starts to get meaningful. Starts getting an actual two wells a year. Essentially save money.
Any reason to believe that the Plains acquisition by Freeport McMoRan is going to change their emphasis on the ultra deep?
Well, you should do that (inaudible). What I would tell you from the outside looking in, I think that they are focused more on generating free cash flow on their side. So I do think, as I have said publicly, I don't think you are going to see us picking up a roe and jack-up rig, and drilling a well in the open water in the next year or two. I think we are moving onshore, where it's a lot cheaper to drill. Quicker to get the formations, and even quicker to bring on production. So whether that would happen with or without the deal? I am not sure. I think we were sort of heading 80% the way there, I think the deal kind of makes it 100% certain. So I think you will see us complete one, two or maybe even three wells that we have right now over the next year, with the Rowan rig. But everything else would be onshore.
I think Chevron, a year to 18 months, will have Lineham Creek on, and then we go from there.
Any other questions? I'd like to thank John and the companies for coming to end the conference. There will be a breakout session in the Riverside Ballroom.
Thank you all very much.
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