Energy XXI (Bermuda) Limited (EXXI)
Annual Investor Day
October 23, 2013 9:00 am ET
John Daniel Schiller - Chairman and Chief Executive Officer
Joan E. Lappin - Gramercy Capital Management Corp.
All right. Welcome, everybody. So go ahead, and get our seats, get this thing kicked off. There are a lot more people online waiting for it to begin. So looks like we allotted time.
Welcome to our fourth Annual Investor Day. Energy XXI, proud to sponsor this event today. I'll cover a little bit of housekeeping real quick. Of course, the disclaimer on everything we're going to show you and tell you today.
For the agenda, real quick, then. We've got 3 separate breakouts after this initial presentation. For those of you listening in online, it will all be webcast. There will be brief pauses in between as we switch rooms.
For those of you in the room, your nametags are color-coded to tell you which of the breakouts to go to. The staff will guide you from here into the breakout that you need to be in, but if you're in -- if you're maroon, you're going to start right here in this room, which is the reserves and capital program. If you've got a green tag, you're going to start in the breakout B, which is exploitation, right here to my right. And if you are blue, you're going to start in breakout C, which is directly out through the back of this room, and that will be the exploration room. Please stay in your assigned groups if you can. We're trying to keep the size of the crowd proper and make sure that you get to see everything. I know everybody wants to -- well, sometimes, you want to say, "we'll, I'd like to sit through that presentation once again," but if you do that, you're going to miss some very good information. So if you can stay with the group, that would be great.
We'll have about 5 minutes in between each for transition. If you can use that time for your bathroom breaks and phone calls, that would be great. We'd like to keep all this moving along very well.
So after the presentation here, John Schiller is about to come up and open it up. You'll have your breakouts. When were done, right at noon, we will reconvene in this room for Q&A, then you can ask as a group. All the teams will be here and be able to follow up. And then after that, we'll have a lunch out where the breakfast was set up and once again, you'll have time to mingle with all the teams who'll be there to answer any further questions you have.
So with that, let's get this thing going, John Schiller.
John Daniel Schiller
Good morning, everybody. Thanks for making it out to our Annual Investor Day. As is tradition, we've got a lot of our technical people and all of our management team for the most part here. I encourage you to ask a lot of question today, look into the things you want to look at and they'll will be more than happy to handle everything you ask them.
With that, let's tell you what we do at Energy XXI. It's an acquire and exploit model from Day 1, and we've done it very well. As we've grown, we've taken a little bit of that cash flow and put it into exploration and you'll see the results of some of that today. And for the [indiscernible] is to deliver good results to you, our shareholders.
We're dedicated to growing. We've done it a lot of different ways. This year, you saw some nice reserve additions. I'm going to go into a lot of detail around those as we move through some of the breakout sessions. I think the key thing for me is think about where we are, a lot of oil in the ground. We went after big oil fields and what we continue to do is deliver that oil to you. You're going to see a very safe predictable program for this year, not a lot of high abnormal pressure test. It's drill normal pressure oil wells. And that's what we have on the agenda, that's why you'll see our production continue to become more oily as we move through this year.
Acquire has been a big part of it. Obviously, it feeds it. You know that -- look at how we have acquired things, we've done a very good job in terms of buying of what we think are very attractive prices on all of our large transactions. They're typically more oily than what some of the peer group has bought, and we've bought at the right price.
One thing I want to take a little bit of time about today is tell you that there's -- everybody that operates in the Gulf of Mexico are good corporate citizens, but there are some that are better than others. And we've been fortunate in that buying behind the majors like all of our fields, we've been with Chevron, Mobil and Exxon, that they were good housekeepers. They didn't just sit there and produce all their fields and let the idle arm lay around. So, you look at the major acquisitions over time and we acquired 58 platforms, only 4 inactive platforms, and about less than 300 inactive wells. Over the last few years, we've taken out a lot of what was there, and so we're in very good position. But the reason we've been able to do that is like what you see in West Delta 30 there, Exxon, over the course of time, we've put 24 platforms into that field. But then there's only 13 remaining, so as they depleted an area, rather than sit and let that portfolio sit out there, which was allowed underneath the rules of the lease with the government. You're only required to clean up your lease once production is over for a year. They were getting stuff out of there. And so, we benefit from that. And that's one of the reasons you see as you go around that we've never had huge P&A liabilities and things like that. The guys that we bought from were taking care of business.
Big oil fields provide upside. From Day 1, that's what we targeted, large mature oil fields. It sounds corny. We keep saying it but big fields get bigger. That's just the way it's always been in our business, particularly when you're dealing with oil. There's a lot of it left in the underground. Average recovery probably across all our fields is about 45% of the oil in the ground. You can look at a lot of core analysis, you can look at a lot of studies. And there's a lot of this stuff, a lot of reservoirs that ought to get us in the 65% to 75% range when they're through.
And it's not just talk. You look at what we bought over time, we've bought about 146 million barrels of reserves. Over time, we've increased that by about 80% of 261 million barrels when you put back in the production that we pulled out of there. So a lot of reserves in these oil fields. They keep getting bigger and this is an example for you, I bet.
Another thing we did this year put a lot of focus on 3P. I won't bore you with all the details but I will tell you in our business, the Gulf of Mexico, you're probably the most conservative definition reserve you can have, we have a lot of lowest known oil penetrations that we're not allowed to book below so everything below there is in the 2P and 3P category. One of the reasons that slide I just showed you had 80% of uplift was a lot of those reserves were strictly moving from 3P and 2P, where we had good amplitude support, we had good modeling of where we thought the capillary pressures indicated oil contexts were, but we weren't allowed to book anything but above the lowest known. So one thing we did this year, a lot more detail about how we went about the reserve process, but we really put the focus on looking at all these big fields and coming up with just how much oil is in the ground and you see it in the 2P -- 3P numbers where we went from 206 million barrels to 310 million barrels equivalent in there.
One of the things we did do is we went to the audit situation. In my career, I've always been on audit mode from Superior Oil to Burlington to Ocean. And the reason we always did audit mode is that was the best to create attention. You want a situation where your engineers are engaged, along with your auditors. When I first stepped to Siegel, they had been third party. And when I realized how silly that was, I'm in a meeting to propose a well and I asked my reservoir engineer how many reserves he has on this well, he goes, "I don't know, that's what -- those actions would [indiscernible] does for us." I tell him, looked at him, "Wait, you're the reservoir engineer and you don't know what your reserves are." He said, "It's not my problem, other guys do it." And that's what happens in a third-party. We're all human. So if you got your platter full, you've got a lot of work to do and someone else to do the reserves for you. After a couple of years, it becomes their problem, not your problem. So when you go into an audit mode, it's everybody's problem. Everybody's looking at the data. You find out that some data that wasn't getting shared. And that's what some of the disconnects were on reserves, so you start sharing that data. And I clearly think it's the best way to move forward.
The model continues to deliver both in value growth, the PV and the reserves themselves and in that asset value growth, and we think we've got a lot of use of this continuing.
This is kind of what we do in an acquisition model. We get in there, we immediately look for ways to get production uplifted by optimizing. That can be better gas lift, it can be reducing back pressure in the field. It can be some wireline work, but it's generally not rig work. Then we start moving into rig work, with completions, it's some wireline recompletions. Somewhere, we do our field studies and as we go through, we end up developing a drilling program and that's when we start putting the money to it. And then as we get all that down, we'll do some exploration down there. Because of where we are in the process right now, the majority of our fields were coming right half of this relevant scenarios here. So the key part of being how to exploit things and here's what we've been doing. And I think, a lot of you in the room who heard me talk about Dr. Evil, but I can't emphasize it enough because there's a lot of engineers in this room and geologists both for us and on the other side but the key thing is engineers and geologists, they think in barrels. Yes, they understand how to make money, what a profitable well is. But in our lifetime, we've always thought about finding 1 million-barrel, or 10 million-barrel discovery. And what we had to do over the last couple of years is rethink that and said, "Look, 10 million barrels of oil is not what it was 30 years ago. 10 million barrels of oil today is a billion dollars cash. And that's real money and you can do a lot of things today from a technology standpoint, from horizontal standpoint, from uplift that you never could do before in $20 oil environments. That's been a big change for us over the last 2 years. It's not as easy as you think. It sounds simple but it really is changing the whole mentality about -- in your mindset, what's -- it's almost like changing the rules of what a touchdown equals, right? It's not 7 points anymore, it's 70 points. So we change the game plan a little bit. And that's what we've been doing.
Another thing, just to point out, I think, sometimes people get confused, especially company like ours that they think you can't grow reserves again, grown in production. In reality, the process works just the opposite, whether you're exploring and developing an exploration success, whether you're acquiring and looking at these big fields, you have to go in there and figure out what you have, identify those reserves, come up with a development plan and then you execute the development plan and get the reserves. And that's what you're seeing [indiscernible] start to do this year after our field studies and identifying the reserves the last year.
One of the things that we pointed out to you last year was the slide where we talked about the next 5%. And as amazing as it is to talk about our reserves went up 50%. The reality is, it's still less than 3% of all the oil in place we have. And that's the leverage that people are missing. We haven't even got to the next 5% yet, we're about 2.5% to have that kind of reserve in place. So there's a lot of oil left in these fields. You can see it historically, over time, how all the different decline curves have been. What we were showing you last year is just what a 5% would do to your production curve. It's just not a big bump on the adjustment. So talk about what really happened to the cost of reserves ads. Our value increased from $4.3 billion to $6.1 billion; reserves went from 120 million to 179 million, 59 million barrels year-on-year and 1/2 of that was PDP and 1/2 PUD basically.
The PDP reserves here, you see what they do for us. They extend the production life and you can see where the big movers were, West Delta 73 and South Tim 54 was the largest chunk, with Main Pass 61 being the rest for us. Remember that Main Pass 61 has always an amplitude-driven drilling, so pretty much anything we do there is a new ad because we can't put in the separate amplitude into the approved category right now. In fact, we can't even put the amplitudes in the 3P at Main Pass 61.
This is a slide that Lee's going to go over with you in a lot of details, but I just want to point it out is when we talk about going from the third-party to audit and put in technical pressure, we let this well get away from us 3 years ago. The rate fell off. All of a sudden, our friends at [indiscernible] slapped a 50% decline on it and they keep it there. We come back, do a little wireline work and get the well back in performance it should be. It's right back on the curve where they'd been all along and there's a huge difference in reserves right there.
PUD delivers. Big delivery for us from PUD. This is actually an area where we had a lot of conversation. You'll see today as you go through West Delta, particularly, not 73 so much but West Delta 30. You're going to see there's a lot of locations we could've booked. But when we made a call that we didn't want to go that heavily putted, if you will, for lack of a better term. And so, what we saw there was a nice increase at West Delta 30, 73 was booked in all of the obvious locations. The results of horizontal drilling we had in that field and then South Tim 54 tied back to that well. I just showed you an up-dip location in it.
Again, I know a lot of you have seen this but as always, it's good to just go over it one more time and remind you. When we do horizontal on the Gulf of Mexico, we're not really looking for permeability. We've got all the permeability we need. What we're doing is making a play on pressure drops. When you look at these vertical wells, we're typically trying not to exceed 500 pounds, but we're pushing anywhere from 300 to 500 pounds of Delta P. And that creates water cone in any way you look at it. And the reason coning occurs is relative water is less viscous than oil. So once you get water coming at you, the relative firm, says the water's going to keep coming. And that's what we show you in that top set of slides is what the cones look like.
We go in there with these horizontal wells. We've been modeling these wells. The big wells are coming on for us at a couple of thousand barrels of oil a day and then that makes them 4,000 and 5,000 barrels of fluid are literally producing less than 10 pounds pressure drop. So across that thousand-foot lateral, the oil is just sort of dropping into your well board. It's much more stable reservoir. And we think long-term is going to get us some much more efficient sweep of the reservoirs.
This shows you the type curves around there. We show you a Mid one. Again, Lee and the guys are going into a lot more detail here on the West Delta 73D. I can see that the majority of the wells continue to be in the high side for us. We've been very pleased with the results, remembering that there's been over 34 wells drilled in our fields by Exxon and Chevron in the late '90s. So we've got a lot of good type curves for the type completions we do where those wells are all making an excess of 2 million barrels of oil. They've been online for 15 years and they're still locked over at 200 and 300 barrels of oil a day with 90% water cut.
Just a quick look at what West Delta 73 says a picture of the model that's outside there, but you can see the big paid sections we continue to log as we drill the laterals, the 7-stacked reservoirs and the opportunities to continue to do that over and over again.
And because of that results at West Delta 73, they're in the process of tripling their production rate right now, as well as outstanding reserve growth. West Delta 30, just a quick deal. I'll give you some sense. It's a huge oil field. This gives you some sense of the 16,000-foot of salt there. As we talk about the pre-salt play, you obviously realize that this has a lot of potential impact to us. The main thing to keep in mind is reservoirs are shallow as 3,000 feet here, all the way down to 18,000 feet on the west side of the structure.
And tremendous reservoir quality properties. So we make a lot of oil, and we have very high recovery factors here.
We go back to that slide I showed you about how we go about the process and here's an example where West Delta, the oil production is higher today than it was when we acquired the field, yet we never put a rig in the field. That's all from hard work, gas lift, restoring some wells to production, fixing holes and tube and making some zone changes, all those type of things that do there, minimum CapEx and we managed to grow oil production over time and now the rigs are coming and we think you're going to see a substantial leap here in our production.
The big thing to remember here is this was found in 1948. It's made 580 million barrels of oil, it was a lot of oil in the ground here. And they're just starting. Again, Jason is going through a lot more details, but we've only mapped about 20% of the reservoirs on this field study, and only 35% of what the production is. There's a lot of work to be done in this field. This is our drilling schedule for the year. You can see the wells we've finished. Don Lino were getting ready to run the gravel back in, and we'll probably have that well on production in the next 10 days. Gunn is drilling, we just got kicked off today, so it's drilling ahead. Merlin, we're going to squeeze the lineup before we drill out, but we've got a liner down to the bottom at 14 well now. And when we've hit the Main Pass, I've already talked about that one. So that covers everything we got going on there. As I mentioned, it's a very oil-focused program. If you follow -- if we keep that production flat over the last 2 quarters, where it's been, what you should see throughout the year is the percent of oil continue to increase and the oil grow. At the end of day, that's 90% of our revenue, and that's what matters. This just to give you some sense of how we start ramping up wells on Ford. West Delta 73 and 30 being the champions of that, if you will. The other fields that we expect big things out of will be South Pass 49, when we eventually get a rig that our government's happy was allowing us to put on a platform, which we think we'll get here shortly. We'll get a rig out there, and we think there's a lot of upside, similar story big, old oil field that's never been drilled in for over 10 years. And all of that will start to add into our well count going forward.
One of the things I think that's unique about the numbers we gave you yesterday is we basically held production flat quarter-on-quarter. When you look at what we're doing, we're only running 2 rigs. We got a rig drilling exploration, but 2 development rigs holding production flat, that would imply if we keep that up, that we've got about a $200 million maintenance level CapEx, which is even lower than what we thought it was, I'll be honest, and lower than those in what a lot of you in the room thinks. So a lot of hard work by the production engineers. We've been talking about reservoirs in the remaining stats. Reality is we've also almost doubled the production and engineering staff, Nelson. We're hiring a lot of young kids out of school. A lot of veterans that we're bringing in to mentor them. And so we pay a lot of attention to our wells and make sure we continue to increase production.
What that growth and repeatability means is double-digit growth over the next 3 years. I think it's important again to mention this is all coming from development drilling. We don't model the Herons of the world, or the Merlins of the world into this or any of the ultra-deep messages doing our development thing and getting volumes growth and cash for the growth.
Talking about exploration real quick. We're going to that with the core assets in the salt play.
We got a whole section denoted -- set aside for this today, so I won't go in a lot of detail, but we're really happy with the setup that's occurring here. There's kind of regional faults that set up a lot of these large fields that we're in and that's what Heron and Merlin are all playing off of. And Mike will go in a lot more details here.
We will talk about Heron real quick. 100 feet of oil. Multiple sands below the original 2 sands that we talked about. I would say it's oil all the way down to 16,700. We have oil samples. We have permeability and pressure data. We felt very good about the quality of oil and quality of the reservoirs. The field -- the rigs are going to leave the field here as we finish up this walk away BSP, that's going to help us determine where exactly the salt is. It's going to drill another well for [indiscernible] and we'll bring it back and do a delineation, which would either be a shallow down dip for the upper sands or an up dip deep well for the deeper sands. And that's what some of the data we're analyzing right now wold tell us.
The Main Pass joint venture with Apache is in prime territory, a lot of big oil fields. That's why we took this deal. As I've said many times on the deep play, below salt. If we're going to hide the 100 million barrels of oil in the Gulf of Mexico Shelf, this is where it's going to be. It's the only place we haven't been able to see. So what we're doing here with wide estimates, what they've been doing in the deepwater without huge success rates, all we're doing is bringing that on to the shelf. And you see that with a setup where our friends at Chevron shot the first one over Bay Marchand, which is the largest field in the Gulf. That included our South Tim 21 field. We're already seeing some neat things off the data at South Tim 21, much better definition of where your sand salt interfaces are. And as we get the next set of data on the block we required for Crete, we're giving better data deep on some of the drilling opportunities there. Sand [indiscernible] Main Pass, Apache's actually finished the acquisition. Now in the processing, move which is about a year process before we have a finished product.
West Delta 30 just gives you some tantalizing information. If you look at the northwest side, you have production down to 18,000 feet. You come over to the southeast side, and your deepest production is 12,000 feet to 10,000 feet, somewhere in that neighborhood. So there's a lot of things underneath that salt that as we do our own WAZ shoots and we process the data, you have more information on it, you'll see some neat wells over in the West Delta 30 field, I think going forward.
Again, back to that sort of Dr. Evil moment. One of the things you have to adjust your head around is the seismic cost too. We did a $150 million seismic shoot with Apache. That's probably five-fold larger seismic program than I've ever shot in my career. But only 2 million barrels of oil will drill a well and pay for it, and that's the change in economics today. And that's why it was easy to just find deepwater. We were late to bring it to the shelf, but the economics are just as good and when the things we're looking on in the vertical salts, we think there's a lot of opportunity to make this data work for us.
And this is kind of a wrap-up slide of what you're going to see on the exploration side, but we've got over 2 billion barrels potential, it's broken into 3 main type plays. Mike will give you a lot more detail around and show you some of the plays with a lot of potential and most of it sits underneath fields where we already have production, we hold it by production.
So we talked a little bit about monetization, that process is going good. We feel very comfortable as we move forward that we'll hopefully find an international player to come in here and put some money into these drilling opportunities and help us recognize the value that's nowhere near any of our numbers right now. It's not in 3P. So if we can get somebody and give up some value but end up putting anything on the book, it's better than where we stand today on those exploration opportunities.
When you talk about the results we've been delivering, we're highly leveraged to oil. Now you see the revenue comes from oil, so oil prices and oil production are key. You kind of get a sense of where our EBITDA has been running pretty consistently around the $200 million a quarter range, and our oil production with some growth in there from 25 to close to 30. And then all prices [indiscernible] over time.
We've done a lot of work on making sure that we put our capital to where it's most efficient for us, and this slide just kind of shows you that as we mentioned, the 3 big fields for us: West Delta 73, West Delta 30 and Main Pass 61, continuously rank out there, and any way you look at it, it's the most efficient places we have. With our portfolio right now, it's in the best money and that's why you see some money going there.
All right. And then higher trading models. How do we get a better stock price? In my mind, we got to show you that there's a lot more coming, a lot more repeatable activities and that the explorations are working like it is at Heron. Follow up with the discovery of Merlin. I think then the salt plays starts taking off on top of to generate consistent results from our horizontal drilling. So we put all that together and hope to continue to see our share price increase.
We continue to fill the engine. We're back to square one. We've made the full cycle. Now we're talking about the next big acquisitions. When we think big oil fields, which you've heard me talk about for the last 20 minutes, the next big set of oil fields, when we look at the history of the majors, they started off a lot at the Gulf of Mexico, '50, '60s, '70s, even the early '80s. In the '70s, they started moving into Southeast Asia. '70s and '80s made some huge discovery there.
A couple of minutes about Southeast Asia. If we to do something there, we're going to return you, we'll come [indiscernible] in the Exxon or Shell of the world. It's going to be a huge field, over a 1.5 billion barrels of oil in place. 500 million produced some number like that, so you got 1 billion oil still sitting on the ground. And we do the same magic we talk about here. We get 5% more out of the ground, that's a huge number for those type plays. And we're not talking about big deals, we're talking about in aggregate, the 2 opportunities we look at right are less than $200 million. And in turns of cash flow and capital project, were talking about things that's basically be funded by the cash flow associated with the properties and no more than 10% of our CapEx at the company level. So that's why we're over there. We don't see big oil fields like that becoming available right now in the Gulf. Certainly, not one field the size of some of these. And we just think it's a very attractive area in Malaysia and Thailand and Indonesia. All of them are sort of in a place right now where their risk of becoming oil importer [indiscernible] exporters. So it's a time where the times are kind of favored us to do a little better terms that have been going on in the past. And particularly, someone with our background who's come behind the majors in other areas and gotten the production of. So that's a reason we look at that.
Again who knows, we're dealing with government, so you never know what the deal is going to come through over there. This just gives you some sense on Malaysia when I talk about it. Very look like same geology. It's the reason the majors looked there when they went there. Daily oily opportunities. They actually separate the oil and gas there. So anything we'd look at would be more oily in nature than gas. As I said, most of the cash flow will cover any CapEx over there.
So what's in today? Well, We hope you see and why you're buying Energy XXI. We're -- As you see, we're working on development of repeatable and predictable programs. We think the horizontal drill in these big oil fields does that for us. You'll see what that's what they allow us to do. We put together a great team. I think you'll be impressed with the members that are here today and take some time and visit with them either during the meetings or after around lunch. And we've got over 2 billion barrels of gross potential on our fields. It's a lot of upside from exploration when and if we want to do it. It's not something we have to go do. And EBITDA and cash flow multiple should be growing and start proving all this all up.
And so with that, I think we're going to release you to head out to the breakout session, get that started. We're going do all the Q&A at the end, Stewart? All right. So take a few minutes at the breaks and head to your breakouts rooms and then we'll all be around with you all there and circulate through with you.
Everybody ready to get started? Here we go. Good morning. My name is Phil Kerig. I'm Director of Corporate Reserves and Business Planning for Energy XXI. I've been in the oil business for 28 years now. First 21 was with Conoco and then Conoco Phillips, and then 6 years with Devon as Planning and Reserves Manager and I've been with Energy XXI since March of this year.
My -- my educational background, I have a Bachelors Degree from Cal Berkeley and Masters in PhD from Texas ANMO in chemical engineering. Last
year we grew our reserves by 50% and we understand that that's a bit unusual, so take some explaining. But we felt for a while that our reserves should be considerably higher than what they were, but feeling it and proving it are 2 different things. We feel we proved it this year, and that we're here to talk about that today. Our plan today is to open the hood a little bit, let you take a peek inside, see the processes that we use and how they're better processes than what we've done in the past. And the processes and the results have convinced us and convinced our third-party auditor that the numbers we've got on the books now are the right numbers. Or at least, much better reflections of what our wells will be producing.
We'll show you some examples of how this better technical work drove these new numbers, and our hope is that you'll leave the presentation feeling comfortable with the new numbers because you'll understand where they came from and understand why they're better numbers.
It all started early in 2013 with our decision to go with an audited reserve process as opposed to the evaluated process that we've used in the past.
And as John said, the audited process really is the best way to go for a number of reasons and we'll talk about those.
A couple of that audit process with good old-fashioned elbow grease. We added staff, we did a bunch of work on the properties, these are properties that we understand better than anybody. We put a lot more time and effort into it, since we're the ones taking the lead on the evaluation site. More time and effort put into something doesn't always give better answers, but at least it's a very good start. We had a great synergistic relationship with our auditor, Netherland Sewell. John talked about the creative tension. Once again, it proved that 2 heads are indeed better than 1.
The 50% growth in proved reserves, we see on the chart on the right-hand side. It extends not just to the proved reserves but to the 2P and 3P as well. It's pretty much a 50% increase across the board, so our total 3P number is in excess of 300 million barrels now.
And then finally, the last bullet point, what the increase in crude reserves means on the PDP wells, and the PDP stands for proved developed producing, and those are the wells that are already online. What that means is that you'll see flatter declines in the reserve report than you've seen before. It's not an instantaneous bump in production. It's just production holding up longer over longer periods of time. And it's that flatter decline that makes it easier for us to grow production period the subsequent wells that we drill.
The movement -- so this slide talks about proved reserves only. The movement from the 120 million barrels we had at the end of '12 to the 180 million, 179 million that we've got now can be seen on this slide. The production, so we start with the 120, we produced 16, we added 13 by acquisitions. Those 2 bars probably don't take up much explanation, but really it's the 2 bars here, the additions and revisions that together amount to 61 million barrels, that's pure organic growth and that's really what we're going be talking about here today. And just a reminder at the top of the slide, these reserves are 100% audited by Netherland Sewell and that's the topic of the next slide.
John showed you this slide, but let me talk about it in a little more depth. First of all, what is a reserves audit? When you think of auditing, you may think of financial auditing, where the auditor comes in and does a spot check. Checks a few of your numbers, randomly selects some things to inspect and if those work out, you pass the audit. The reserves audit is not like that at all. The reserves audit is a complete technical evaluation by the reserve's auditor, just as he always did for us in the past. The billing is the same, or even more. They do all the same work. They still do forecast on 100% of the properties. The difference in the reserve's audit is we are now fully engaged, fully staffed up doing our own evaluation. The way it works is we share the same data with the auditors that we always have. They'll do their evaluation, and we'll do ours and then we get together and compare notes.
On any individual well or field, if we agree with each other, that's it, we move onto the next one. If we find we disagree, then we'll take down the next level of detail, okay, how did you come about your numbers? What assumptions did you use? What data did use? How did we come about our numbers? We compare those and then figure out why we're different, figure out how the data, figure out which of those 2 interpretations is best supported by the data. It's all data-driven. And then, we'll settle on one method or the other. Or sometime we'll settle somewhere in between if we find that both of the methods have some merit. So that's what a reserve audit is. In a reserve audit, in order to pass a reserve audit and be able to declare that our reserves have been audited, we have to be within 10% of our auditors estimates and that 10% applies at multiple levels, that's 10% on a total proved basis of the 180 million barrels. With Netherland Sewell, they're a little bit unique in our industry. They also say that to meet their audit standards, you also have to be within 10% on the PDP because they understand that the banks are especially interested in the PDP. So you have to meet the 10% criteria on those 2, also 10% on a 2P basis and within 10% on a 3P basis.
So that -- just trying to underscore here, they're doing all the same work in the past. They have to pretty much agree with what we've done in order for us to pass the audit.
To give a little bit more detail on what's changed. And really, the key change that drove everything is the change to the audit process. In part, we reorganized around it. We added new positions. We put Lee in to coordinate the technical evaluation for the Exploitation department. We added a senior reserves engineer to the corporate reserves staff. I came in, in March as well. Plus, we added another dozen technical positions within the Exploitation department. This is the kind of manpower increase that you have to have if you're going to do an evaluated or an audited process, where you're doing your own evaluation. So they've done those reserves, and now we have the staff in place to execute on them, especially on the PUDs. So overall, that was about a 40% increase in the technical staff.
We also applied the best available technology to the problem of reserves estimation. There's a standard method that most people use, which is the rate-time plot. You plot the rate over time, and if you plot it on the right kind of scale, you'll draw a straight line. That works great sometimes, it doesn't work at all other times. So what we've done is we've applied different techniques as well to find which technique is best applied to this reservoir. And it's not always that simple rate-time plot, which has advantages -- it's really quick, but it doesn't always give you the best answer.
We worked out methods to let us do this efficiently. Lee will talk a little bit more about those. It's going to be kind of a recurring theme today, the use of multiple methodologies to cross-check and verify, as the flight attendants will say. And we're also -- you'll see, as well, that we're not just trying to pick the highest number. Even if we wanted to do that, we couldn't because Netherland Sewell would not buy off on that. We're trying to pick the method that gives the most consistent answers. Or pick a set of methods that get to the most consistent answers that best honor all the data. Even if there's data that we really wish didn't exist that we didn't have to honor, you do have to honor all the data to get to the right answer.
Okay. John showed this slide -- just to make a note, in your books, the -- we've used the phrase organic growth here. We figured that will be less confusing than the phrase you see in your books of reserve increases, I think it is. If you want to make that correction, please do.
If you remember, back to the waterfall chart, those 2 bars that I said that we've talked about, are the -- that total up to the 61 million barrels. And that's pretty much half PDP, half PUDs. I explained the PDP. The PUDs are the proved undeveloped locations, so the proved locations that we haven't drilled yet. So it's about 50-50 there. And what the PDP -- what increases in PDP means, I've mentioned before, essentially flatter declines than you would've thought with lower PDP reserves. It also equates to higher recovery factors. John mentioned it that this 61 million barrels have increased, the 50% reserves increased. Sounds like a huge number, but if you put it in terms of original oil in place in the reservoir and recovery factor, it's less than the 3% increase in the recovery factor. So I think that, that puts it in a little bit of perspective for me.
And then, that flatter decline, of course, makes it easier to grow production.
On the PUD side, what that gives us is we've now got a significant inventory of low-risk, repeatable drilling opportunities. West Delta 73 is a perfect example of that. We've got a good track record last year of some pretty good repeatability and some excellent success. And we expect more of that from those PUDs. And we expect West Delta 30 to turn out the same way.
You'll hear a lot more about those 2 in the next breakout room. The PUD additions as well, as the second bullet point says, they're dominantly in our core assets, our strategically aligned assets that we've got staffed up. We've got rigs in or rigs coming, and we will be prosecuting those opportunities. In fact, we've started already.
Just a little bit more on these 2 sources. I think the PDP source, I've already cleared pretty well. The PUDs, dominantly in West Delta 73 and West Delta 30. The West Delta 73 additions, from a couple of different sources. One is that we had some vertical or really, conventional PUDs on the books already and booked at very low recoveries that are consistent with the conventional PUD. And then, we drill them horizontally, added a lot of reserves per well by doing so. Took some remaining PUDs, vertical PUDs, conventional PUDs, converted to horizontals, et cetera. You'll see that a little bit more later. But it's dominantly from that horizontal program. And West Delta 30 had an awful lot of attention put on it this year, had an asset team on there. They've torn it apart, reservoir by reservoir. They have a much better understanding than ever before. This asset was pretty much under the radar for the previous owner. And frankly, for us, for the first year or so of ownership, but now that we've turned our attention to it -- and it is a world-class field, and they do get bigger. And the asset team is not even half done with interpreting the potential of that reservoir.
So let me turn it over to my colleague.
Hello, my name is Lee Williams. I'm the Manager of Planning and Reserves. I have 13 years industry experience. Did my undergraduate and graduate studies in petroleum engineering at Texas A&M, then went to Burlington in their offshore group. After Burlington, I was one of the original technical staff at Southwestern Energy, and rode that from $100 million to $15 billion market cap. After that ride, went to ERT, which is a small deepwater player. And then, after that, came over here to Energy XXI about 1.5 years ago.
Early this year, I was tasked with the responsibility of spearheading our effort to go from the third-party results -- or report, to an audited report and really initially focused on the PDP growth. That is -- that was Stage 1 of our process. And historically, the auditors had done rate-time. That's the most common approach. It's quick, it's easy, it's generally very conservative. But it's not necessarily the correct method. What you have to do as a petroleum engineer, to really understand your reservoir, you have to look at the problem for multiple angles. Every methodology that we have as a petroleum engineer has different limitations, has different assumptions and they each tell one part of the story. So you have to do every methodology out there to really get all the pieces together and to see the total picture, and that allows you to get a much better and more accurate analysis of the reservoir.
However, it's not quick, is not easy, it's very labor-intensive. A rate-time projection may take 15 seconds. Some of my projections, doing the multiple methodologies, were 4 to 6 hours per well. But with that rigor, you get better results. Some of the ones I have listed here, if you can see them, you have the rate-time, rate-cume, bottom hole pressure versus cume, GOR. 3 different types of oil or water test versus cume production because they all tell you something different. And I'll go through some examples now. This is a well that you've -- John has shown. This was one of the wells we purchased from Exxon. The well has made almost 7 million barrels to date. It was a nice, steady decline for almost 10 years. We've made the acquisition from Exxon. The third-party NSAI fitted their decline as a very conservative decline. As you can see, it really doesn't match the historical decline. After a little blip in production during the handover from Exxon, I reforecasted year-end and basically just used the same decline. We then had another year of production and they just walked that same 50% decline forward. So every year, they would just walk it forward instead of really analyzing things, we're walking it forward every year, without explaining why the production was not matching their forecast. They were just being very conservative.
And then we got another year of production, and this is where we forecast. And this is where we came in and did multiple methodologies and really got a good technical understanding of what this reservoir was doing. And it's actually -- if you look at the total history, it's a natural 10% decline. The incremental reserve gain is 3 million barrels from what the previous auditors add to what our -- new report. So that's a 3 million gain -- barrel gain here. In addition to that, we got a much better understanding of the reservoir and we were able to add a 4.3 million barrel PUD updip. So we actually had a 7.3 million-barrel add, due to the much more rigorous analysis of the reservoir. And we'll work through that with Netherland Sewell. They were in agreement. It's just they had never done that level of technical detail but by doing the creative process and the multiple meetings with them, we were able to get this incremental 7.3 million barrels.
And this plot here shows -- it's a summary of all the different technical analyses we had done on that well, where we had done 2 different types of rate-time or rate-cume, inverse rate-material balance time, which is a pseudo steady-state solution, the foil tubing pressure cume. I attempted to do 3 oil cut or water cut, but it's really not applicable because the oil cut was too high. I mean, I would have liked to have used it because it actually yielded a much higher EUR estimate, but it's really not valid. The data is not there to support it yet. It will be possibly later, but we generally see, as you have, a convergence of all the different methodologies that were in agreement, with around 10 million barrels. We ended up booking just slightly under that.
And here's the previous estimate, that was around 7 million barrels. It took a lot of hard work, a lot of effort. It was very labor- and time-extensive, but it yielded a much clearer understanding of the reservoir. And we got a much better result there because of that.
Another example, this is from a South Tim 54 field. This is one of the legacy Exxon horizontal wells that we've talked about. This well came on, you have nice straight -- I mean, you just draw a straight line, I mean, it's what people is going to do. If you do that exponential, you got about 1.2 million barrels. However, that's not what the wells in this reservoir and the horizontals typically do. They each generally break over. And after 6 years, this well broke over. So what happened then? We did a new forecast and you get a second exponential decline, and you're going to get about 1.9 million. So you gained 700,000 barrels just due to the performance of the well. However, rate-time in a strong water-drive oil reservoir is not necessarily the most correct or most accurate methodology. It's the quickest, but it's not the best, which is why you need to do all the multiple methodologies to get a better understanding of what's this reservoir telling you. Because if you take this forecast here, that's a straight line on the second segment and you go to a different plot, this is an oil cut-cume, where basically, you're plotting oil cut as a fraction of the total fluid produced versus cumulative oil. This is an empirical stand-in for your relative permeability curves, which is a function of what the reservoir is giving you. It's independent of well conditions. You plot the data on this plot -- I mean, you get a nice straight line. So you forecast that second exponential decline that we saw a second ago, and this breaks over. It really doesn't honor the data. However, if we then draw the straight line here, to a minimum oil cut of 2%, which is the economic limit, you end up getting an EUR of about 2.7 million barrels. So you just gained another 700,000 barrels of reserves. So then if we take this and take this line and convert it back to rate-time, here is the data. We take that oil cut-cume line and you hit a hyperbolic decline, which is actually much more representative for the entirety of the data, let's say, for this one segment. As you can see, here's the first forecast, the second forecast -- I mean, this one is much more representative of the data book in the oil cut-cume plot and the rate-time plot. However, during the audit process, we were only able to book about 2.2 million, so there's still about 0.5 million barrels to go. And that's part of the problem with the audit process, you still have to negotiate a little bit with the auditors because they're generally very conservative. So we still have some upward growth here on this well.
Next, talk about some of the PUDs. The 2 fields that had biggest the PUD growth were: West Delta 73, which were due to the horizontal results; and West Delta 30, which is a big salt dome field, due to the field study that John has alluded to.
Let's go to 73. We initially, in the past year, drilled, we have these 5 conventional PUDs that were on the books. They average about 380,000 barrels each. We drove those as horizontals in the past year. The results of the horizontal program was very successful. Some went from about 380,000 to over 1.5 million-barrel per well. So we added 1.2 million barrels per well in new reserves. So we've got a gain of about 6 million barrels here. We also had additional PUDs that we had not drilled yet. We converted these from the conventional wells that were averaging about 590,000. And we've pumped those up to 1.1 million. It's still a lot more conservative than we've seen with our horizontal program, but we gained about 3 million barrels here.
In addition, we added 19 new PUDs due to the results of our horizontal program, and that gained 15 million barrels there. So all told, we've had about 29 million barrels of upward growth at West Delta 73 due to our horizontal program.
Horizontals aren't perfect in every reservoir, but where they are perfect, they're the -- I mean, it's a great solution. West Delta 73 is the perfect application of horizontals, and you can see that with our 29 million-barrel growth.
The other field, West Delta 30, that's the one we're doing the field studies. And truly, that's just looking for added slots or updip locations. Stuff that may have been too small back at $10 or $30 oil, now it's $100-oil that break prospects and PUDs. This is an example, this is a shallow zone that has never been produced before. You got great size and continuity. You've got logged pay. Unfortunately, the well that logged this was lost due to mechanical issues while producing from a lower zone. We have sidewall cores that show it's oil. We have seismic amplitudes that can form the structure. We added about almost 3 million barrels of proved reserves and almost 4 million barrels of 3P reserves, and we'll be drilling this, this year. The predrill economics yields a profit-to-investment ratio of over 13. So for every $1 you invest on this well, you get that $1 back, plus an additional $13. I mean, tremendous economics. The team for West Delta 30 has, so far, found 49 drillable locations. We were able to book 20 of those so far. I mean, this field has made almost 600 million barrels. It's world-class rock, the -- very, very prolific. And I know Jason, in the next room, he'll go into why. But we've only mapped about 50 of the reservoirs, so we got tremendous upside here, both from a drilling development standpoint and from additional reserve growth in the future. And as we go to developing the reserves, I'll let Phil go back to that story.
One more typo on Slide 16. In the title, I think it probably says 20 million. In your books, that should be 29 million.
This slide just summarizes our reserves position at the end of last year versus the end of this year. Showing the split between proved, probable and possible. And if you work through the math, you'll find that most of those numbers are right about a 50% increase over last year. Actually, with PV-10, it's a 65% increase in last year, driven primarily by the fact that our possibles were a lot gassier last year than they are this year. I think they went from 60% oil to 75% oil or something in that ballpark.
Okay. So let's talk about what we're going to do with all these pretty new PUDs. What we'll be doing is -- well, we've been ramping up our drilling program a bit. So this shows -- same slide John showed, we expect to drill about 21 wells this year, ramping up to 27, and then, 30 the year after that. Largely focused on West Delta 30 and West Delta 73, but also having fairly material drilling programs in the other fields, particularly, in fields where we have PUDs. We have some PUDs in various of the other fields like Main Pass 61, South Tim. We'll be getting those done, getting those drilled within the mandatory 5-year period.
And then, as you see on the right of the slide, there's an awful lot more to come, 138 additional opportunities that will drill and/or convert into PUDs, as the data warrants doing so.
Capital, we expect from the $675 million this year to $800 million (sic) [ $850 million ]. The bottommost, the maroon bar that you see on the bottom plot, that's the development drilling wedge. That's where all -- in addition to other wells that we're drilling that aren't proved and developed on the books right now, probables, what-have-you. And within that wedge, about half of each of those amounts is the drilling of PUDs. So $160 million or so. $170 million this year, $220-or-so million next year or $230 million. And then, there's another 2 years after that, that are in the $220 million to $230 million range, so within that 5-year timeframe, we're spending about $1 billion drilling the complete inventory of PUDs that we have on the books right now, at fairly level rates. So it's very executable.
However, we do expect -- as big fields get bigger, we do expect to replenish that PUD inventory as we drill it off.
So let's wrap it all up. To be a great company, you have to have at least these 5 things. The assets. You have to have some of the best assets, and we do have some of the best assets I've ever seen. I've worked, for 28 years, worked all around the world. Seen a lot of good assets, seen some outstanding North Sea fields, and something like West Delta 30 is as good or better than any of them. So we've got big fields, we've got great fields and you've heard it before, big fields really do get bigger.
On the reserve size -- side, obviously, we've got the reserves now. We probably already always had them, but knowing or believing that you have them and being able to prove that you have them are 2 different things. We've done the legwork now to prove that we have those reserves. So the 180 million barrels is what's on our books now. And we know what it will take to convert that into production. And that's in our plan.
The people side. We've got some of the best people on the -- in the business, all the way from the management team down to the technical staff. Having been around this industry a few years, you can tell the difference, and there is no substitute for having great people. On our balance sheet, we're very comfortable with where we are. We've recently increased our revolver size by about $240 million, showing that our lenders have the same confidence that we do in our ability to deliver the goods. And then finally, if you got drilling going on, you need the rigs. We've got the rigs that we need for this year under contract. And then in the future years, the modest increase in rig count that we need, we don't see any problem in securing those. Add all those things together, and you've got a great company to work for and a great company to invest in. Thank you. I'm -- I'll be more than happy to take any questions.
You had a 50% increase in reserves, and that occurred at the same time you went from evaluated to an audited reserve estimation. How much of that -- that 50% increase do you think was attributed to the change in the reserve valuation? In other words, was this a onetime -- how much of this was a onetime event in terms of the reserve increase?
That's a good question. I would say, the lion's share of it is attributable to not just the change from evaluated to audited, but what that means in terms of how much work that we do and the use of multiple methodologies, the dynamic tension. I think as Lee showed in some of his slides, that there's more to come because there are places where we couldn't get Netherland Sewell to entirely buy off on our forecast, and so there's room left.
You talked about people being an important part of the story. Can you just tell me, as far as some of your young engineers, what you're doing in terms of recruitment? Why people are excited about coming to Energy XXI versus some of the other players in the Gulf that, seemly, have a lot of opportunity as well, such as EPL, for example?
Can I get that repeated? It was a little fast.
Okay. So I was just talking about recruitment of personnel. How you're able to attract talent in some of the younger engineers you have on your team, and why they're excited about coming to Energy XXI versus some of your peers that also have a lot of runway?
Lee, you can get Tom to talk about that.
Tom? I think that Tom mentioned it earlier.
I can answer that. I'm Vice President of Exploitation. All the reservoir engineers, geologists, geophysicists work in my group. And we've actually been very happy and very successful in recruiting a lot of the younger professionals into our company because -- I think you'll hear from Jason Newbanks [ph] next door after this session. And Jason worked for Chevron for about 5 years and came to our company about a 1.5 years ago. I think a lot of the younger guys are looking at the bigger companies and they get -- they can do more in our company than they can in a big company. Because with Chevron, you'll hear that Jason worked the [indiscernible] marsh and field. Worked South Louisiana, worked the Shelf. And he was able to do a lot of things there, but at Energy XXI, he can wear multiple hats. And he's not carved out in just doing the reservoir engineering job. And so why they're coming to Energy XXI? It's the story here. It's -- there's a lot of growth. We started in 2006, we've grown tremendously. That's seen out there in the industry. And Jason knew of Energy XXI at Chevron and he liked the story. But you'll hear from Jason, you'll hear from Brian. We've got Andy. We've got a lot of young guys in my group right now that we didn't have a year or 2 ago.
Just a question on horizontals, as reservoir engineers, kind of what does surprise you about the performance of the wells thus far?
With the horizontal program, it's -- traditionally, we think of horizontals in the shale plays, where you're trying to get as much link to maximize your kh, your permeability, so you have to have huge laterals with multiple fracs. In our reservoirs, we already have the permeability, so it's all about minimizing your Delta P to avoid toning in the water. We've been able to get -- I've been surprised on the quality of the completion. While we're getting, basically, 0 skin with Delta Ps of 5 or 10 psi and we're getting pretty uniform influx into the wells, so far, when we've been able to run production logs. And just the results speak for themselves. The wells have outperformed our initial expectations. We developed the tight curve -- you saw the tight curve plot in John's presentation. Those are based on the legacy Exxon wells. So far, we generally exceeded those tight curves, so we've been able to get better completions than Exxon got. And we've been able to produce them better. So it's been a very pleasant surprise in just how great the horizontals have worked at West Delta 73.
Why do you think more companies don't do the in-house reserve evaluation and third-party auditing as opposed to just doing the full third-party evaluation? Why is your process fairly unique or unusual?
It's really not, most companies actually do audited reports. Generally, when you have smaller companies or companies that are just starting out, you do the independent third-party, just because you have -- I guess it's a credibility issue because you don't have a history, so the banks want that independent third party report. But once you reach a certain critical mass, the industry standard pretty much is to go to an audited report.
It's also probably resource constraints as well.
You usually don't have the manpower when you're really small because it's a very labor-intensive process. If your staff -- if you have limited staff, it's either trace the drilling rig to add value or do the reserves. And the staff's going to concentrate on what adds the greatest value, at least initially.
So what you're indicating is that when you went to the new reserve thing, you're going to the more standard thing. So last year, and the year before, your reserves were sort of discounted a little bit because you were small and have much credibility. And now you've gone to an audited way, so they're closer to being right than they were before.
I would say these are the best reserves we've ever had. They have been analyzed much more rigorously, I mean, Netherlands Sewell has analyzed them in great detail. We had multiple meetings. So we have probably the closest to the most correct answer we've ever had. I mean, you never know, there are -- there is no such thing as a perfect reserve because it's something that's influx-ed with product price. But the numbers today are the best we've ever had. Yes?
Can you discuss how you risked your production growth via your planning with the reserves at the shale?
When we're doing a long range -- well, let me step back for a second. When we're doing AFEs on wells to approve a specific well for drilling, we'll use a very specific set of forecast for that well. The actual cost we expect, the actual reserves we expect for that well. When we're doing a long-range planning or a near-term planning type of exercise, we'll use a little bit more average type of assumptions, a little bit more generic. So that the kind of assumptions that we'll use are more how much production uplift would we expect, on average, for every dollar of capital we spend. And that's kind of at the core of this type of forecast. and we'll use an assumption somewhere in the neighborhood of $50,000 per BOE per day for long-range planning type of purposes. And we feel that's a pretty good representative average of what our program would deliver.
If we look at the list of wells to be drilled, it's my understanding -- is it safe to say that you should start with the lowest or deepest, I guess, reservoir? Because that way, you can book the reservoir's updip from it? I mean, I just want to understand the whole strategy...
Historically, that's the way you've done it. You drilled a conventional or almost a vertical well. So you drill that 1 well and you completed it at the deepest zone and you worked your way up. What we're actually planning to do now, with $100-plus oil, we don't want to leave these uphold zone sitting there for 30 years. So we're actually going to be drilling horizontal wells. So it's going to be single well per zone. You'll have uphold recompletion, but that -- I mean, we're not going to let them just sit there, we're going to drill separate wells to capture those reserves also. So it's -- we're not necessarily going from the deepest up, since it's going to be independent wells. We're going for the highest value from the get-go.
Okay. So how do we get this list? Can you give us a sense of -- sort of the order? Is this in order, [indiscernible] Dark Crusader, Black Widow?
John Daniel Schiller
I think we're just about out of time. So -- and we'll be -- the next session begins [indiscernible] break. You got about 5 minutes...
Your next breakout room will be to your left.
Good morning, everyone. My name is Jack Albers. I'm a reservoir engineer with the West Delta 73 team. I've 30-plus years experience in the oil business, more than 7 of that is with Energy XXI.
I'd like to introduce the rest of the West Delta 73 team. We have Allen Berlin. He's a geologist. He has 30-plus years experience in the oil business, more than 7 of those with Energy XXI. We have Chuck Henry, another geologist with 20-plus years experience in the business, 6 more -- at least 6 of that is with Energy XXI. We have Andy Sims. He's a reservoir engineer with 2 years of experience, both of those with Energy XXI. He is an [indiscernible], and we're taking care of him. We have Richard Burnett. He's a geophysicist. He has 30-plus years in the oil business. He has 1 year with Energy XXI. And Brian Goudie [ph]. He's a reservoir engineer with 5 years experience, 1 year with Energy XXI. There'll be time for questions at the end of both of these presentations, so please hold your questions until then.
West Delta 73 field is unique. We're successfully adding reserves in production. We have a multiyear inventory of development wells. Last year in June, when we talked to you, we started our drilling program with vertical wells and had not yet spudded our first horizontal well. Since then, we've kicked off our horizontal program with great success. The success continues.
There's some very large fields in our neighborhood. West Delta 30 is the second largest field in the Gulf of Mexico shelf. Grand Isle 16/18 is the fifth largest field. West Delta 73 is the eighth largest field on the shelf. I'd like to point out the differences. One of the differences between West Delta 73 and the other fields, you see the yellow salt in the other fields to the north. Grand Isle and West Delta 30 are salt dome structures, which are fairly typical in the Gulf Coast. They're faulted, highly dipping -- they're faulted with highly dipping beds, and there's a large number of smaller reservoirs. West Delta 73 is a different kind of reservoir. It's a large flat 4-way structure with limited faulting. And the reservoir sands can cover a large area and are continuous over that large area.
Okay. I'd like to show you 2 different seismic lines. On the left is West Delta 73. On the right is West Delta 30 or which is a typical shelf field, as I said. West Delta 73, you see the lines are relatively flat going from side to side. That represents almost 5 miles. With West Delta 30, you see salt on the right, and as the beds come up near the salt, they start dipping very steeply. The red and the blue lines you see there are faults that are breaking up the reservoirs. Maybe it's a little easier to see now. Here's kind of what I see when I look at these seismic sections.
The graph at the top that you see here is our quarterly average daily production since acquisition. Crude is in green. Gas is in red. And production from horizontals is shown -- and that's oil and gas production, is shown in the green and white bars. In -- since March 2011, which is on the left-hand side of this graph, to the current production, we've tripled our production. And 2/3 of that latest quarter production -- more than 2/3 is from horizontal wells.
Let's talk a little bit about performance. This is a plot of all our horizontal wells to date. And barrels of oil per day is on the left side, and across the bottom is production time in months. The green and blue lines are the type curves that we use to estimate initially the range of production rates and reserves we can expect from our well at West Delta 73. The type curves are based on the historical production from the 9 Exxon horizontal wells that were drilled in the field in the late '90s and early 2000s. 3 wells are exceeding the type curve. That's Hyden, Big Sky 2 and Bearclaw. Also, on this plot, in yellow, is an average vertical well. You'll see that it starts at about 200 barrels a day and declines from there. One of the advantages of the horizontal wells in the field is horizontal wells start at more than 1,000 barrels a day. There's quite a difference.
The dark gray shape you see there is a narrowband around the type curves that shows production from these horizontal wells is very predictable. As an added highlight, the star that just flew in represents the initial production rate for our Hulk well. That's an H-35 well, producing 1,700 barrels a day. It went on production 2 weeks ago. It appears to be another above-average well at this point.
Let's talk a moment about reserves. First, with remaining reserves, since acquisition, we've doubled our remaining reserves going from 32 million to 64 million barrel equivalents. However, when you look at the estimated ultimate recovery, we've grown the estimated ultimate recovery only 10%. My point there is a large change in remaining reserves isn't necessarily a large change in ultimate recovery.
Let's talk about the factors in our reserve growth story. We focus now on full reservoir reserves and historical recovery factors. We doubled the team size from 3 to 6 people. We're using our field study simulation results. These are simulations we have Schlumberger build that modeled individual reservoirs and give us an idea where remaining reserves might be, and it supports our full field -- our full reservoir reserve numbers.
I guess the horizontal program's success, it's largest effect is really on the program economics. Horizontal wells produce more reserves and rate than a conventional well does. So it requires fewer horizontal wells to drain the same number of reserves. It drives the PV-10.
What you see here is an F-35 structure map with 10-foot contours, with -- overlaid on that in color is a remaining net oil isopach from our Schlumberger F-35 simulation. The reds are the remaining -- or the thickest remaining oil column. This reservoir is 3,300 acres from where it's original oil-water contact is, there in that red dotted line.
I'll give you an idea of the scale. This rectangle represents the size of Central Park at 843 acres. Before, when we were doing proved undeveloped reserves, our methodology was looking at existing wells that have gone off production due to mechanical reasons, and we've looked -- we'd assign a proved undeveloped reserve -- a proved undeveloped well near there to recover those reserves. What we do now is calculate the total reservoir volume based on the current oil-water contacts that we see in the wells that we've just drilled. We use the historic recovery factor to calculate remaining reserves, then we place these horizontal wells to recover those reserves. This method does require a lot more manpower, and it's probably more than you could expect from a consulting engineering firm that's doing an annual reserve report.
Here's the proved undeveloped locations for the F-35 sand. There's 7 horizontal locations, 6.1 million barrels gross recovery from those 7 wells. We may add more locations based on the performance of the first 7 wells.
What you see here is log sections for our 7 successful horizontal wells. Behind that is a model of the field showing the F, G and H sands. In the previous slide, I referred to the F-35 sand. There it is highlighted for you. Also you saw out front, a physical model of the horizontal target sand, similar to the picture, complete with horizontal wells. 7 out of 8 of our horizontal wells have been successful. 70% of them have been targeted to the F sands. We're currently drilling the Gunn well, which is a horizontal well, to the F-40.
We have numerous oil targets. This is a section of the type log for the field with -- going from the F sands through the H sands. The total cumulative production for these 11 sands is 197 million barrels and 223 BCF. The F sands alone are bigger than 98% of the shelf oilfields. The F sands would be #22 on the list of oilfield size on the shelf.
There've been over 300 wells drilled on these leases. It means we have a lot of data and a lot of control, showing where the oil and the gas are. The F sands are the largest and most prolific sands. There's numerous other oil sands developed, mostly deeper than the H -- F sands. The H sands, which is shown at the bottom, are up to 1,000 feet deeper than the F sands.
On this slide, I'd like to first comment that easier -- the word easier on the title is a relative term. This cartoon shows an example of an F sand, and it's about 5 miles from side to side. Here's how the oil and the water sit in the sand. There's a fairly thin layer of oil underlain by water. The slide demonstrates the flatness of the field. It's less than 1 degree of dip, which, to give you a better idea, if you had a conference table 10 feet long and put a book less an inch thick under 1 end, that would be about 1 degree of dip. So this well -- these reservoirs are very, very flat. And that flatness is important because, along with the continuous reservoirs that extend over a large area, that allows us to keep our horizontal wells more easily and more effectively in the reservoir and remain inside the target zones.
You saw this slide in John's presentation, and I'll try to get through it fairly quickly. In conventional wells, you get significant water coning developing early. And the important thing to me, as a reservoir engineer, is you leave a lot of oil behind. There's significant undrained reserves left between the well locations. When you look at the horizontal wells, the wells -- the only part that's horizontal is in the target zone, where we tend to be about 1,000 feet in the -- horizontal in the target zone. It reduces water coning by spreading the pressure drop out of a larger area. So we get higher rates but the pressure drop is lower in any particular location.
Each well drains a larger area, which leaves fewer undrained reserves, increasing our ultimate recovery. This horizontal technology isn't new. But horizontal wells lead to more effective drainage, especially in these kind of reservoirs. West Delta 73 is a great place for horizontal technology.
Here are some of the things we're doing to ensure our continued success. We have a program to log every one of our horizontal producing wells. That will give us an idea exactly where the production is coming from and how it's coming into the well. What we can do with that information is improve our production practices and perhaps improve the way we drill the wells. We're also going to continue our reservoir modeling program. We've modeled -- currently, we've completed the models on the F-35 and the F-40 sands. The F-30 model is in progress.
These are large, complex reservoir models that Schlumberger built for us, and they actually simulate -- they match the historical production for all the wells in the field, and they simulate how future production will occur. What it does, it gives you an idea where there might be more undrained reserves. It helps you with new well locations, and you can optimize your production. You can say, "What happens -- if we try to increase production by doing this, what happens in the reservoir?" So it's really a helpful tool.
We're also working to improve our drilling and production practices. This is a Big Sky 3 post-drill geosteering model. And the first geosteering is what we call the process controlling the direction of the drill bit in real time while we're drilling based on readings we're getting back from the drill bit. The model behind -- the model that you see there represents the F-30 sand after we drilled the Big Sky 3 well.
The target oil zone is brown, and it -- the white line represents the wellbore post drill. We're trying to keep these wells in the zone that they see thick for 1,000 feet. And this is one of the bits almost 2 miles from the drilling rig. Predrill, this model was essentially flat and didn't include this bump that you see here. The bump's a couple of feet high, and it's localized, localized meaning, you can't see at any -- in any of the offset wells, and it's also too small to see on seismic. So there's no way that we could know that it was there.
Below the model, you see a log section with the sands in green -- excuse me, the sands in yellow and the target zone in green. And imagine while you're -- while we're drilling, this log appears as you drill from left to right. You'll see early on, as we drill this well, we started to follow the top of the sand. We try to stay near the top of the sand to improve our recovery. And as we did follow the top of the sand, because this was the only -- was only a localized bump, we popped out off the top of the sand. As soon as we'd recognized that, we started turning the well back down into the sand, and the result was a 1,300-foot horizontal, with over 1,000 feet in the reservoir. Our process includes a post-drill review to analyze how the geosteering process went and comparing what we expected to what we got.
This is the same F-35 structure map with the net pay isopach laid over the top of it that you saw before. But it represents -- but posted here is our fiscal year 2014 drilling program. You see our 2 successful wells in pink. That's Big Sky 3 in the F-30 and the Hulk in the H-35. There's 2 more wells to be drilled in the D platform program, which are right here and here. The D platform rig will move to the B platform, where it will drill 2 wells this fiscal year. And then there'll be 5 wells drilled off -- drilled with a new rig off the C platform.
That 2014 program leads out to the next 2 years. We have a 3-year rig program shown at the top of this slide. It's a -- yes, 3-year, 2-rig program, excuse me, and the total capital is $335 million. There's $75 million for a new platform. This program will lead -- yield a 13% compound average growth rate in our production, and that production is 85% oil, by the way.
I'll try to give you a summary in 15 minutes of 2 years of hard work. I don't feel I can really do it justice. However, here are the main points we're -- I'll try to make today. West Delta 73 is a unique, big and flat oilfield well suited to horizontal technology. We have a multiyear inventory of prospects that are adding reserves and production.
Thank you for your attention. And now I'd like to turn it over to Jason Eubanks.
Okay. Good morning. I'm Jason Eubanks. I'm the reservoir engineer for the West Delta 30 field, and I'd like to do some introductions really quick before launching to this field. It's a field we're very excited about. We got a lot of opportunity here. We have really developed a lot of oil-drilling opportunities. And let me introduce the team before we get into that.
Like I said, I'm Jason Eubanks, reservoir engineer. 5 years of experience, only 1 year with Energy XXI, previously worked at Chevron, developing their Gulf of Mexico shelf assets. Bruce Dawson is our geologist. He has 31 years of reservoir -- or of industry experience and 1 year with Energy XXI as well, and he's worked at Sun Oil, Burlington Resources and Hilcorp. And Richard Burnett, towards the back, is our geophysicist. He has 30 years of experience, 1 year with Energy XXI as well, and he's worked for Unico [ph], BHP, Burlington and ConocoPhillips. And the 3 of us were hired at roughly the same time to work the West Delta 30 field. The management saw some opportunity in this field, and they hired a new team to develop it. And so what we're showing you today are the results of that work so far.
Before I turn it over to Bruce for a geologic overview of the field, I wanted to tell you why we're so excited about West Delta 30. First of all, this is the most prolific field on the Gulf of Mexico shelf, bar none, and we'll talk about why that is. The field is also undervalued when we acquired it. I think, a little by us and a little by the previous operator, it was undervalued. It's taken us a little while to get our arms around the opportunity and the size of what's there in that field.
We implemented an intensive field study, have identified about 50 oil opportunities, drilling opportunities so far. We've booked about half of those, and we're looking to book the other half in the near future. And then a significant development opportunity exists in the $100 oil environment, and we'll talk about that in a few slides, about what that means and historically, how the field has been developed and what kind of opportunity remains now with commodity prices the way they are. And then maybe, most importantly, is our multiyear development plan starts now. We have a rig moving to the field starting next month, and we're going to start turning the reserves into production.
So with that, I'll turn it over to Bruce.
Thank you, Jason. The map in the upper-left corner says West Delta 30 field, located about 50 miles south of New Orleans, Louisiana and just west of the Mississippi River delta. On the larger map to the right, the brown lines represent faults. The yellow areas are salt uplifts, and green areas are oilfields. West Delta 30 field is a giant oilfield located along an east, west counter regional fault system, better known as the turbulent trough [ph]. This system goes from south Louisiana on to the Gulf of Mexico federal waters. Several giant oilfields are associated with this fault system that runs from south Louisiana.
West Delta 30 is one of the largest oilfields in the Gulf of Mexico, as Jason explained. Total production since discovery in 1948 is 580 million barrels of oil and almost 1 trillion cubic feet of natural gas. This field is 65 years old, and it's still producing oil. Water depth is shallow and averages about 37 feet. Energy XXI operates 4 federal leases, most with 100% working interest. And at the bottom, the production curve for the last 3 years shows some decline, and we are working hard to increase production significantly in the near future.
To demonstrate the huge size of West Delta 30 field, I compared it to the largest volcano on the island of Maui in Hawaii. On the left, the largest volcano rises 10,000 feet above sea level and is about 20 miles wide. In comparison, on the right, the West Delta 30 salt stock, shown in yellow, is 16,000 feet high and the associated oilfield is about 16 miles wide. This salt stock created structural traps for oil and natural gas reservoirs at all depths from 3,000 to 18,000 feet below sea level. Over 40 sand bodies have produced oil and gas from 250 reservoirs in this field. Most of these reservoirs are highly porous and highly permeable, and in total, they represent about 10 million years of geologic time. All these factors combined make West Delta 30 the most prolific oilfield in the Gulf of Mexico.
Energy XXI operates 4 OCS blocks. We have 100% working interest in 3 blocks and a high working interest on the block in the west. And this area is over 20 square miles. The scale bar at the bottom is 5 miles and demonstrates the large size of this field. Energy XXI leases cover many of the prolific reservoirs in the field, but only about half of the entire width of the field.
The gradational colors around the yellow salt are on the A3 structure maps starting at about 4,000 feet below sea level. This map was made by combining seismic and subsurface interpretation. The tan lines are faults radiating away from the salt. The green dots are oil completions in the A3 zone, and this zone has produced over 70 million barrels of oil on structural highs near the salt.
At this time, I would turn it back to Jason.
Thanks, Bruce. Okay, so I said West Delta 30 is the most prolific field on the Gulf of Mexico shelf. What do I mean by that? The second largest in terms of production, second to the Bay Marchand field, which is operated by Chevron. My previous experience with Chevron, I worked the Bay Marchand field. I'm familiar with the reservoirs in that field, familiar with that development.
And the difference between the 2 is that -- are the rock properties. The rock properties in the reservoirs of West Delta 30 are world-class rock properties. I mean these kind of properties are world class, not just Gulf of Mexico, I mean, really in the world. The porosities we see here are extremely high. The water saturations are very low. You see in the cartoon, it's kind of a simplistic view of the reservoir rock. It has sand grains surrounded by water saturation and then porosity in the middle. And the porosity is where the original oil is at. And so it's obvious that the more -- the higher your porosity and the lower your water saturation, the more room you have for oil, and that's what we have in West Delta 30, high porosities, low saturations and with very high permeability. And we also have very strong water drive in these reservoirs, which help to push that oil through the porous spaces, and we really don't have a need for water injection in almost all of our reservoirs because of that.
So you combine that with horizontal wells and what you get are those extremely high recovery factors possible. We're showing 50% to 80% recovery factor here. These are -- in reservoirs that were developed with conventional vertical wells, that we've seen these recovery factors. So we think when we start developing this with horizontals, we're going to be at the higher end of that 50% to 80%. And that's 100% a factor of the reservoir properties that we have here. And we also have high fluid rates that are possible because of horizontal wells and the high permeability as well. So what does that mean? That means that our attic oil reservoirs can hold very large reserves and we can produce them at pretty large fluid rates, too.
We have a lot of those sands stacked on top of each other. This is a type log of about 1/3 of the sands in West Delta 30. And there's not enough room for dozens of sands on 1 slide. This is about 1/3 of them. That's a snapshot. You guys can see the reservoir properties. You see the cumulative production, kind of see what kind of sands we're talking about. But there's another 2 slides just like this. And so when you stack all of these sands on top of each other, what you get is a prolific field, a field that is more prolific than anything out there on the shelf. The reservoirs are large. The sands are great quality, and they've really produced a lot of oil with high recovery factors to date.
When I said the field was undervalued, what did I mean by that? Here's a snapshot in 2010 -- of what we acquired in 2010, and we had very little development plan that was in place. There was no development plan set up for us. There was no path to a development plan, like we had in some other fields, where there are multiple opportunities that Exxon had identified for us before the acquisition, that we've kind of worked their development plan for the first few months. So they didn't have that. We didn't have a lot of geologic data, and so we really had to start from the beginning.
And so there are a lot of reasons why we were -- that was the situation. I want to touch on a couple of them. You guys can read the rest. But I think the most important is inability of West Delta 30 to capture any capital in Exxon's larger portfolio. I mean they had shale gas, they had deep water, they had international, lots of emerging plays for them to invest that money as opposed to what they would have seen as a declining asset in West Delta 30. So that's the large driver of almost all of these factors.
Seismic is another one. We're using a seismic reprocessed data sets that Exxon did not have. We've -- we're the first to use this. We just kept this recently and that's something that they didn't have and we're unable to move value, the kind of reservoir potential that we see.
And then last, minimal utilization of new technologies, last thing I'll touch on Exxon. We have these technologies -- invented a lot of these technologies but something was really utilized in West Delta 30, 1 horizontal well is all that was utilized. A lot of things that we're looking at doing simulations, dump for BSP [ph], that kind of thing. Nothing was being done there and so that's presented a really a big opportunity for us.
So the results of this field being undervalued are apparent in field development history. So showing a couple of graphs here. The top graph, the maroon bars are representing the number of wells drilled per year since the field was discovered. And the green lines represents the daily oil rate over that same amount of time. And then the graph below shows the average U.S. oil price over that time period. You see that aside from the initial field discovery and the result in peak production, commodity prices really driven the activity in this field. And when you see the commodity price increase, relative to what it had been, you see an activity increase and you also see a -- either a spike in production or you see a flattening of the decline. What I would like to point out is that after 2005, there's been very little development in this field period. And most of the development in 2005 was strictly for gas reservoirs. No oil development really. And so it's pretty easy to make the inference that about 2005 issues, when Exxon decided that they'll probably going to be exiting the shelf or at least divest in West Delta 30, and you kind of see that in the history of how this field was developed from a technical team standpoint to it, as you look back through the old record, they really stopped seeing much attention to West Delta 30 and it was clear that they have moved on. But coincidentally, that's about the time the oil price has started going up to their highs. So I said that there are a lot of opportunity in the $100 oil environment. In reality, there was opportunity in the $50 oil environment and the $60 oil environment. They just made a strategic decision to exit that part of their portfolio and send out, and we're left with the opportunities that we can develop at a $100, which is really significant for us.
Another way we feel was undervalued was in the strategy for producing and handling water. The graph shows the amount of water produced per completion and the top Gulf of Mexico shelf oilfield. And you guys have heard John talked about this in his presentations that moving water and these strong water drive offshore fields is the key to increasing ultimate recovery. The more water you move, the more oil you're going to get. And you're just going to keep washing that oil through the pore space. And what you see is that West Delta 30 really wasn't operated in that way and part of that is that they had -- their facilities weren't really designed to handle a lot of the water. The completions weren't setup to handle a lot of water in the wells and as a result, West Delta 30 is showing the lowest amount of water produced at any of the top field. So we've radically changed that strategy. We've installed upgrades to water handling. We're now drilling horizontal wells to move more fluid. Our completions were able to handle that kind of water production. And so we've already made that switch and we're looking to move West Delta 30 up to increase that ultimate recovery for the reservoirs.
Talk a little about the platforms that we have. Started out with that 24 total platforms with Exxon developed out here initially. And Exxon was very good stores, not just of this asset but of everything that they had. And over time, when they have a platform that they feel like had no future utility, no economic wells left to be drilled, regardless of oil price, regardless what I thought might happen in the future, they abandoned platforms. And so now, at the time of acquisition and today, we're left with 13 platforms. And what that means is that we don't have a lot of D&A liability associated with platforms that are unused, that are junked, that are just waiting to be -- have money spent on to have them abandoned. All of our platforms are in relatively good shape despite their age. They all have wells, for the most part, producing on them, facilities on them, crew quarters people live in. So these are well taken care off platforms. But what it does present is an opportunity for us to add value by adding additional platforms where maybe there was never a platform. They're replacing a platform that was removed in 1965. Those kind of opportunities are quite a few. I'm showing 3 proposed platform locations here. We're evaluating a lot of platform locations to kind of see where we can add more platforms to be able to book more reserves. We haven't booked any reserves associated with new platform jet. We're going to wait until we make the decision on where we want to invest that capital for the facilities before we start booking our club locations associated with that.
So we've talked about how we got to this situation, why the field was undervalued, why the opportunity exists. But now I talked to you guys about what we did with it. And the 3 of us: Richard, Bruce and I were all hired to evaluate the West Delta 30 field, find out if there's anything left. And maybe this was a field that we didn't want anymore in our portfolio. We needed to know that. And so we instituted a very rigorous technical field study and what that really involve was a lot of detailed mapping and that was driven by seismic process that I talked about earlier. And then also on the other side, from the reservoir engineering standpoint, a lot of reservoir characterization, really making the production fit, really looking at the rock quality. We're really looking at historical production and making it all tied together. And you'll hear me say this again, but we believe that we have the best idea. We understood these reservoirs are better than anybody ever has. And that's allowing us to really find some oil that has been forgotten and most of these reservoirs. And because of that, we've been able to drive a lot of organic growth. We've identified, we said 50 drilling locations. We booked reserves associated with about half of those so far. And that has driven our accretion of our development plan. And we're about to start executing that development plan next month. We have a rig showing up in the field to start the post-rig line. And this field study is ongoing right now despite being in execution mode. We're still working this field study. We're still generating opportunities and we'll show exactly how many opportunities we feel like we have left. But as we identify more, we're going to keep updating that development plan. So we move our best opportunities to the front to maximize the value.
The seismic reprocessing really drove our field study. You kind of see it move from left to right over time here. The 2012 RTM data is what we're using now and this is something that only we've been able to see. Only we've been able to use this and you see we have a lot clear visual of the salt. We can have a better idea where reservoirs are in, where they began, where you have changes in quality and we're really using that to our advantage to be able to jump-start the mapping process here.
So I won't go through all of these points. You guys can check out what we're doing, what our process is and what our results have been for our field study. I think that the important point here is that we have really torn these reservoirs down. I'll say it again, we understand them better than anybody else has and there really is a drilling location factor in this, pretty much every couple of days, we're churning out another opportunity that we're putting down on our queue to be able to start booking them and putting somewhere in the development plan.
And we've got a long way to go. We've looked at 50 reservoirs so far and we've mapped those, studied those. That only accounts for 20% of the total reservoirs in this field. And so we've really only scratched the surface of the amount of reservoirs here, and it's not like we've picked the most productive or the best reservoirs here. That only accounts for 35% of the historical production. So it's safe to say that what remains in the 80% is pretty much exactly what's in the 20% we mapped as far as reservoir quality, reservoir size and the type of opportunity. So we got about 200 reservoirs left and we expect that we're going to have, I mean 30 million barrels of 2P reserves of what we booked based on the 20% number. And so everybody can do the math on the kind of opportunity that we feel like is remaining in that 80%, which is why we're still working the field study very diligently.
Speaking of reserve add. Like I said, we increased our reserve significantly and we doubled our approved reserve in the field and more than quadrupled our probable reserves. And that was about a 240% increase in PV-10 and our probable reserves are -- have a value of about $2 billion to us right now in West Delta 30.
So where did those come from? Where did those -- where do we get those reserve add and you guys have heard from Phil and Lee about our reserve adding process and what we did with our PDP producing wells decline curve analysis, that's some of the ads here. But most of the adds are from our field study, straight from our mapping, reprocessing, and all the reservoir engineering work that we did on this. They're mostly all PUD locations, behind pipe locations, and all of them are oil. We didn't book a single gas product at all. We're looking for oil. That's what we're developing and that's what we booked. And almost all these are attic oil. So these are reservoirs that are above current producers or recent producers for the most part. So that is close to slam dunk as you give for type of opportunities that we're looking for. And all these reserves have been third-party audited and none of these adds are the result of any kind of commodity price changes. These were all newly found, newly identified map projects.
So within those PUD locations that we have, showed net reserves here on the left and then our 3P breakout and we feel like the 2P reserve, our probable reserves, that's our most likely outcome for the wells we're about to drill and we have 42 million barrels of net reserves booked to those drilling locations. We think that once we get these things online, we kind of show the track risk, success with the auditors and ourselves. We really feel like if there's an additional 14 million barrels that we're going to be able to book on this. And that 14 million barrels is about $1 billion in value, and that's going to come with no additional capital but associated with the wells that we're already going to drill to get to 42 million [ph] that are already booked for us. So a lot of upside there even on the locations we've booked.
So I'll give you guys an example of what kind of wells we'll be drilling. This is 95% of the PUDs that we booked are the same style, large reservoirs tracked up again the salt dome. Historically, they've been developed with multiple vertical wells. Producing less than 1,000 barrels a day of total fluids, producing very high water cuts very quickly, and at high drawdowns. So these wells are affecting our coning lost of water because we have the strong water drive, pushing up from the bottom from the natural [indiscernible] So what you get is wells that our watery now, high water cuts, not very economic late in life, and you have these fingers of clean oil in between that remains. And in the past, those reservoirs was just abandoned, that was it. That reservoir was done. So now with horizontal wells, and developing these reservoirs in that manner, we were able to come in with horizontal get up above and get into an area where now it's economic to get into that attic oil area. And we will draw these reservoirs down at much lower drawdowns and we're able to move that undulated oil water contact. That front. We're able to move that in a much more uniformed manner and sweep everything, and get those -- not only we're getting the add volume, we're are also getting those fingers of clean oil in between. And then additionally, we're moving 4 to 5x the fluid of the horizontal well, so -- well it wouldn't have been economic. And the operating costs are roughly the same between vertical and horizontal through us. So where a vertical well may have been uneconomic at 20 barrels a day, that comes much earlier when you're making 99% water in a vertical well than a horizontal. Now we can make 5x the rate and even at 99% water, we still have very economic well in late life stage, which is going to help us continue to water watch this reservoirs or continue to get our ultimate recovery up. And just for reference, we have some lags or some wells that have drilled through or we consider this a for fully swept version of reservoir in a lot of our sands. And we have residual oils of around 8%, which means that all that oil has been produced. We know we can sweep that reservoir. We know we can get the residuals down to 8% or 10%, and that's what were trying to do here. So a lot more upside of these wells aside just the added volumes that are booked.
The first well that we're going to be drilling in our upcoming rig line is the stripper well, you guys have probably seen the stripper well if you followed previous presentations. This was the 1 opportunity that was identified. It was the only opportunity that was transferred over from Exxon when we got this field and we're finally going to drill first well, couple of untested fault blocks or couple of untested sands in a fault block. And then we're also have a PUD location in the A sands as well so we'll be able to develop one of our PUD locations in the first well.
Now I'd like to point the economics. $10 million drill and complete cost, looking to $71 million MPV, a risk [indiscernible] of 6. So you invested dollar, you're going to get your dollar back, plus 6 more and those are incredible economics. Just for reference in my previous job at Chevron Gulf of Mexico shelf oil prospects, we were drilling anywhere between a 0.35, a 0.75 field verizon. And we were happy with those, given us good return but this is in a completely different league and that's a testament to a kind of field that Exxon developed that now we have. The opportunity -- so the reason why they're #1 oil company because they have these kinds of fields that no one else has, and now we're taking advantage of that ourselves. And so it's really more a testament to what the field is and anything of it, us versus Chevron are doing differently.
So I think reserves are great. We are adding value, were building a queue but whoever meets the road and we start converting those to production, we start getting paid for these and that's what were doing starting next month. We're starting with the 1-rig program, moving to a 2-rig program starting next fiscal year, going to look to drill that 32 wells, about $300 million in capital and as about 31 million barrels of reserves will be developed in that are associated with those wells. And we expect our production to increase by about 35% annually over that time, and almost all this production is oil. It's very low GUR [ph] just 85%, 90% oil for sure.
So we kind of talked about the field, very detailed about the field and talked about the reservoirs and kind of understand we've got some good opportunities there, but in the larger company, how does Energy XXI really move the needle for, how does West Delta 30 really move the needle for Energy XXI? I think that with the world-class field and we're evaluating this using these technologies, seismic processing, looking at horizontals, looking at simulation material balance and you name it. We're trying to do that in this field to find that oil because we've had such great success so far. There's lots of incentive now to keep looking for that extra little bit. Where is that? We've identified a lot of shallow normally pressure oil opportunities, which means that they're cheap there, they're quick, they're easy to put online after we drill them. We can drill them in existing facilities, give us very high return. And our field study keeps generating those opportunities. And I can say before, our probable reserves represent a PV-10 of about $2 billion. And so compared with the market cap for the entire company, that's a significant amount of value that we have in this field that we think we can exploit. And again, main importantly our development plan is in place now, whether or not something is happening 2, 3, 5 years down the road, and if we're starting next month then we're going to be starting this.
So all that means that what can you expect from West Delta 30 in the next fiscal year? I think, I'll say it again, we're going to convert reserve in the production. We're very focused on that as a team and we're going to start drilling next month and we're looking at evaluating new facilities potentially, also looking for ways to accelerate that development plan and more staff maybe using consultants for some work, maybe even using additional rigs. Whatever it takes, we're looking into that to figure how to optimize and we have the first 50 wells. I mean, honestly, we're doing whatever we can to get those wells drilled because we already know what they are.
And then we're going to stick with what works. We're going to stick with our field study process. It's working and we have significant reserve adds. We're going to expect significant reserve adds again. We're really focused on continuing to book reserves even though were in execution mode right now we're going to give the field study going because continuing to build queue, continuing to push for further development and made more aggressive development plan we identify those opportunities.
And you guys heard from West Delta 73, it's in the middle of a development plan having a lot of success after only 1 year of horizontal program. And we expect that we're going to be able to build on top of that. We're going to stack our reserve adds on top of that. We're going to stack our production on top of that. We're going to stack our successful wells on top of that and were going to have a core area, a very high-performing fields this time next year. And I expect to be here talking to you guys about our specific successes with the wells that we've drilled and how our development plane is coming next year. Thank you.
We have some time ready for a couple of questions.
Talk about the [indiscernible] West Delta 73 [indiscernible]
I think, I mean, we have pretty thick sands than most part. If not anywhere near the centers those in -- The deep is much deeper but we have sands that are 100 feet thick that we're looking at, it's pretty easy to keep horizontal well and 100 feet, 80 feet, 50 feet. We have some skinnier reservoirs but we're confident that we can place the well in a place where it's easy, easier to drill the well and still going to give us that high recovery. So were not anywhere near a center well [indiscernible] and West Delta 73, for sure.
At this stage, do you know how many of these 39 wells at 73 and the 32 with West Delta 30 are going to be horizontals over this next couple of years?
At West Delta 73, they're all planned plan to be horizontal.
And john have a slide in his opening remarks showing the economics of horizontal versus a vertical with 7-month payout versus 89 based on that, you've never drilled a vertical well but I guess, it's not that simple. What makes a target drill those to horizontal?
I can answer that. With answer to your first question. West Delta 30, I would say 75% of the wells will be horizontal and for us it's really comes down to function of reservoir shape I mean, when you have water pushing the oil up if you don't have enough room at the top of the reservoir to put a 1,000 foot long well in it, we have to go in with the vertical well. That's the only way you can develop that reservoir herein. And so that's what our decision point is, if we can fit a horizontal we'll fit a horizontal. If the geologic -- the reservoir shape doesn't allow us to do, then we're developing that would a vertical well and that's what we can do.
I guess, how do you characterize [indiscernible] Can you talk about that [indiscernible] did you guys look through in fiscal '13?
Yes. I think the Grand Isle experience was pretty eye-opening and really a learning experience for us. The last 2 well they drilled out, actually they've got that pretty successful wells down. The difference I think -- a big difference between West Delta 30 and Grand Isle, first of all, is we have very strong water dry, and so we're not worried about a lot of gas patch, we're not worried secondary gas patch [ph]. Secondly, in Grand Isle, they have problems with mineralized zones that they thought were sand but in reality, they were not. There wasn't any permeability there. We don't have that problem here, there have been lots of wells have drilled. A lot of [indiscernible] over 1,000 wells drilled in this field. So a lot -- we have a lot of penetration points right up against salt but are actually going to be drilling down from those enemy because we don't need to get way up right against salt for these things to work. So we've lagged these, we know they're not mineralized, we haven't seen any mineralization really anywhere around the dome and any of the reservoir so that give us a lot of confidence and also with the well control, now we're going down the previous penetration and we feel really good about that. And I would say that half of our PUD locations were actually going down deep from previous penetration where they lost the well or they didn't really want to go for it in that zone or something in 1960, something standard up. So we have a lot of penetration to help us up.
Just the [indiscernible] do you know what the facilities cost that you guys have planned? You have 2 platforms that you want to...
Yes. I think we're not sure exactly how we're going to develop that, couple of different scenarios maybe a larger production facility with multiple satellite time back or maybe you put in a couple of larger platforms to have their own production facility. We're really not quite at that point yet, that's why I said we're evaluating those locations. It may be that we installed a case on with 3 wells in 3 or 4 different places and that allows us to run multiple rigs on those places and then we have 1 large facility. We're looking at a lot of those things. So no, I think there's a big range of what the cost could be depending on how we can optimize that development.
So going back to 73, looks like at June you were doing, call it 5,000 barrels a day. If I look at your estimate for a 13% CAGR going out to 2016, it would imply, 7,200 barrels a day, even with the traditional decline curve in the Gulf, how do you drill 39 wells that are all horizontal and have that kind of growth. It seems overly conservative to me. Would you be able to reconcile that?
Yes. I don't often -- well I often get called overly conservative by my CEO as one of them. But what you're looking out there is, you have the underlying decline of the existing wells. You have, our 2014 exit rate, or the 2014 average is about actually 7,000 a day. And so you're giving a 13% compounded growth from that, which gives you a lot bigger number. Also those 39 wells we're drilling, there's some of those, 5 of those are injection wells to help maintain the pressure. So they aren't all producing wells. I think it's about time for us to move over back to the main room for more questions. We'll be around during lunch. If you have any further questions, we'd be happy to talk to you. Thank you.
My name is Michael Kane. I'm the Geoscience Manager for Energy XXI. I've been working in the industry about 35 years, the bulk of that on the shelf and deepwater. With me here today is Ross Saunders. Ross is our Chief Geophysicist. Ross has in excess of 30 years' experience, worked for City Service, Burlington Resources, Kerr-McGee. Joined Energy XXI in 2006 as one of the first 2 geoscientists on staff.
Ahmed Ammar is also here. He is a Senior Geophysicist with Energy XXI, started his career with Mobil. He also has approximately 30 years of experience. He's worked primarily on the shelf and deepwater. He also has experience in international. He worked for Anadarko for 11 years. He's worked several of the basins around the world. He worked the Middle East and North Sea.
Also, Irion Bordelon on my far right. Irion spent 9 years with Mobil, followed by several years with Ocean and Flores & Rucks. He also worked for some smaller companies. During his tenure at Mobil, he worked Nigeria, Congo and Thailand. Also here is Ron van Mourik. Started his career in 1979 with ExxonMobil. Worked with federal waters, then went to Burlington Resources, worked at Gulf of Mexico shelf and then spent 6 years at Newfield Energy working on and offshore. Ron also jointed Energy XXI in 2006. Joe Ozment, Senior Geophysical Advisor, began his career with Exxon before moving to Burlington Resources. He and Ron worked projects together at both companies. After Burlington, Joe spent 6 years working for Mariner Energy in the deepwater. He also jointed Energy XXI in 2006. So between the 6 of us, we have approximately 200 years of experience in the industry.
Today, I'm going to talk about the untapped potential that Energy XXI controls as a result of acquisitions in the richest portion of the Gulf of Mexico basin. Following this presentation, the 6 of us will be available for Q&A.
Today, I'm going to talk about the counter regional trend on the Gulf of Mexico shelf. John showed this pie chart in his opening address. The pie chart is separated by 3 main exploration types: the pre-Miocene, the Deep Miocene and the salt dome portion. Today, I'm going to focus primarily on the salt dome portion. I will mention -- I will show an example from each of these other portions of our portfolio at the end of the presentation.
This map highlights giant fields around the world and where they're located. A giant field is classified by in excess of 500 million barrels of oil equivalent. In this case, the green dots you see around the world are oil fields, the red dots are gas fields. The equivalent being the conversion of the gas field to an oil field. There's a concentration of these giant fields in the vicinity of the Mississippi River Delta, which is also coincident with the core area of the operations of Energy XXI.
This same study concluded that where giant fields have been found in the past, more giants will be found. This map is a zoom-in version of that same study showing the giant fields in the Gulf basin and also the 2 giants that we operate in the Gulf of Mexico, West Delta 30 and West Delta 73, which you've already seen in the breakout session.
This is -- this red box is the area of our core operations in the Gulf of Mexico. Giant fields live here. We believe more giants will be found deeper.
Amoco, Phillips and Anadarko, in their '80s and -- late '80s and early '90s, tested the subsalt play on the shelf. All the wells that were drilled are shown here on this map. The discoveries made are shown here by these stars. This map -- this play was somewhat successful but didn't really capture any very large hydrocarbon accumulations. The play then went from the deep shelf into the deepwater were -- huge discoveries were made in the subsalt and are continuing to be made in the subsalt. And that's primarily a function of seismic technology and the ability to image under-the-salt features.
So with the drilling of the Heron well and Main Pass 295, this area that was characterized as vertical movement dominant in this part of the shelf was pretty much ignored until this well was drilled this year by Apache. It opens up this play in an area where we are positioned to take advantage of this discovery.
So Energy XXI, let me briefly explain this slide. The Heron discovery was drilled here on this salt feature. The salt features are shown at these yellow blobs with blue outlines. The red lines are counter regional faults with the direction of offset or drill shown on each one of these faults. The term counter regional means that in an extensional basin, the Gulf of Mexico is an extensional basin, the regional faults in general are down to the basin or offset to the south. In this case, these faults are offset to the north, counter to the regional, hence, the term counter regional faults. These counter regional faults are connected to the salt features and they're related to them in structural development.
Also on this slide are all of the Energy XXI acreage as shown here in this orange color. And each of the field names is shown in the black boxes. The only one that's not on this map, Vermillion 179, is offset 100 miles to the west.
In the eastern portion of this counter regional trend, Energy XXI formed this joint venture with Apache. This is an area where we have just completed the acquisition of this WAZ seismic data, and we'll be processing it over the course of the next year. By virtue of this AMI, we were invited to join Apache in drilling in this Heron well and Main Pass 295.
Let me go briefly into the AMI. February 2013, we formed this AMI joint venture partnership with Apache. As part of this agreement, we share 25% interest in this WAZ shoot, in this area of 135 blocks. We also gained access to 26 blocks by virtue of this deal and the drilling of this well, this Heron discovery well, that we are currently logging and complete -- we're about to complete the logging operations on. This well will provide valuable deep control for offset Energy XXI 100% owned acreage in Main Pass and also to the west in the counter regional trend, in West Delta, Grand Isle and South Timbalier.
So focusing in on the Heron discovery, let me explain this slide. This is a map view of horizon that was drilled with the Heron wells. The salt is outlined here in yellow with a brown outline. The overhang is shown here by this faint transparent yellow. The well location is located here. It was virtually a straight hole through the salt. The 2 blocks that we owned by virtue of this JV are shown here, Main Pass 295 and 294. This is the counter regional fault, and you'll hear this over and over in this presentation. You'll see this on several of the features.
And the next slide will be this northeast to southwest seismic line that John showed in his presentation. This is pre-stack depth migrated seismic section that is directly through the discovery well drilled here in Main Pass 295. This section ties back to a well 13 miles to the southwest in South Pass 62. This is a well drilled by Shell. This is a D33 well drilled back in the '80s. This section is the same target interval and found pay throughout this interval. We found pay in this section under the salt and it's all oil. This well actually tested 5,300 barrels of oil a day and 26 million cubic feet of gas before mechanically failing.
This line is to demonstrate the difference between time-migrated data and depth-migrated data. The section on the left is the time-migrated section showing what would be a possible interpretation of the salt image. You can see that the salt body is very difficult to see and that it's almost virtually impossible to map underneath the salt because you don't see seismic reflection here. By virtue of depth migration, this salt body, which has a sediment -- a velocity of about 1,500 feet per second, is built into a model with the sediment velocities that range from 5,000 to 8,000 feet per second to generate this depth-migrated section. There's a whole series of steps and iterations that occur in this process to go from this image to this image. We feel very confident that this step in the depth migration is fairly accurate in that we encountered the base in the salt about 100 feet from the pre-drill estimate of where we thought it would be. So we think this is a fairly decent image, and we look forward next year to an even better image with the WAZ acquisition.
Now we'll move to the west. From the Apache JV to Main Pass 73, shown here in the yellow box, we own and operate blocks in this area 100%. Some of these acreage is held by production, some is primary term acreage in the federal waters. Some is in the state waters' acreage. Currently, in the Main Pass 73 area, we are refining our salt models. The early time-migrated data that we had, a very simplistic [indiscernible] shape of the salt. In our second iteration in 2010, you can see a more complex image of the salt emerging. And finally, our latest salt model that we have, shown here on the far right in this block diagram, is a very complex salt feature with targets below and beneath the salt. And on this section here, you see the current salt model and the old salt model superimposed over the top. So we believe that the Heron well has provided us with deep sand control. We know the quality of the sand, we know the reservoir fluid type and we can tie that back to deep targets in Main Pass.
Continuing to the west. In West Delta 30, along one of these counter regional fault system, you've seen the West Delta 30 field. It is the largest field that we operate on the shelf. It is one of these counter regional features. The deep targets on the south flank under this salt tie to the same age section that was found in the Heron well productive. Again, the progression from a pre-stack time, a fairly recent pre-stack time where the base of the salt is virtually invisible to a 2011 version of the pre-stack depth, and finally, to a reverse time migration section showing a better salt sediment interface. We see better continuity in the seismic reflections underneath the salt. And you can also see the deepest targeted sections on the south flank of this feature.
This 3D rendering of the West Delta 30 deep salt flank shows the salt body in yellow and the horizon map from bright red to blue. This is from high to low structurally. You see this is trapped underneath the salt against the salt. This is the same Middle Miocene section that was found in the Heron well productive. The 12,000 wells drilled on the West Delta 30 field only targeted down into the Upper Miocene section. Cumulative production to date is 580 million barrels and 933 bcf gas. We think deeper sections here should find in excess of 100 million barrels.
This is one of the maps that's generated with this most recent depth-migrated data. The counter regional fault shown here to the north, the outline of our acreage in West Delta 30, 31 and 21, the salt feature in yellow, the salt overhang in transparent yellow and the structure from this reddish color to blue is high to low. So you can see that we control the highest portion of this feature where the trap is located.
This is the same image the John showed in his presentation. This slide, you can see, from this pre-stack depth-migrated data the deepest-producing horizons on the south flank, the deepest-producing horizons on the north flank where it's not under the salt and well imaged, and the map that I just showed you, this 18,000 foot horizon. So this section from here down is virtually undrilled on the south flank of this feature. This is the same section that found Heron. It's the same section I'm going to talk about in Grand Isle 16/18 and part of the deeper part of this section to be drilled in Vermillion 179.
Moving further west along this same counter regional system in the Grand Isle 16/18. I'm going to talk about a prospect here in Grand Isle 16/18, Glendullan and Glenlossie. On this map, on the upper left, you see the counter regional fault. The salt is yellow. The transparent is the yellow overhang. The structure from the red color to blue is high to low. We control all of these acreage 100%. Some of this is federal, some state. Most of it is under operated-producing properties.
I have 2 seismic lines shown here. ExxonMobil actually developed this prospect, and this was part of what we inherited in the package from the Exxon acquisition. This line on the upper right-hand corner is AA prime, runs across the feature. You can see the targeted section under the salt overhang. This is, again, Middle Miocene section, the same interval that found pay in the Apache Heron well and Main Pass 295. This is the data Exxon used to map. We are currently using this data set. This is a north-south section through the salt feature. This is a pre-stack depth-migrated section from Fairfield, and we're currently refining that picture using this data. But the image is virtually -- the structure maps are virtually the same. We think there's about 81 million barrels of oil equivalent in this feature.
Moving to the south here. The yellow box shows South Pass 89. We own and operate 2 fields here by virtue of the Exxon acquisition. We have deeper potential identified here beneath the salt overhang. In the upper left is the structure map of the deepest producing horizon for the South Pass 89 field. The Gettys prospect is shown here. The conceptual well path is shown on the conceptual cross-section on the right, and the producing horizons are shown in here. These are the deeper targeted sections beneath the salt overhang.
This is the 11th largest oil field on the shelf. 83% of the production that you see in this slide is from this area right here on the salt beach between this counter regional fault and this piece of the counter regional fault that peels off the structure here. The reason this doesn't look obvious by inspection is that this section is much deeper and contains stacked reservoirs relative to this section, which is much flatter and has fewer targeted section. Only the deeper section produces on the north flank of this feature. So that the best part of these counter regional domes is always on this south flank of the feature.
Just to show an example of how the Main Pass 295 feature and the South Pass 89 feature are alike and not alike. The South Pass 89 pre-stack depth-migrated data set shows steep dips on the south flank. There's steep dips on the south flank of the Heron well. Gentle dips on the north flank of both features. The salt overhang is much more pronounced at Main Pass 295, which is why all of the section that's productive is from here, shallower. That section has produced 122 million barrels and 95 bcf around this salt feature. We've now targeted section that was not seen on that salt dome in this interval.
South Pass 89, it was a little easier to see the image and the production is down to about this level. This dome has produced 194 million barrels and 876 bcf from this interval. The deeper targets are shown here under the salt overhang.
Stepping through the progression of seismic technology on this feature. In 2001, this is an image of the post-stack time-migrated data. You can see the deepest producing horizon interval shown here in red and some deeper reflectivity in this red box. The green box, these were the deepest producing horizons in the field. But the base of salt image is virtually invisible.
In 2011, 10 years later, we have a pre-stack depth-migrated data set. You can see a very clear subsalt image, and you can see these seismic reflectors much more clearly. And finally, in 2012, we acquired a reverse time-migrated depth section and you can see some of these images are even clearer along this salt base.
In the lower left-hand part of the -- this next slide, the Vermillion 179 is in this inset box. This block is on a counter regional fault -- in this counter regional play. It's 100 miles to the west. The Vermillion 179 joint venture with ExxonMobil is a counter regional prospect with huge upside potential. We believe the South Pass 89 feature provides a great analogy to the currently drilling Merlin well in Vermillion 164 -- in the Vermillion 179 area. By virtue of this AMI, we gained 50% interest in 54,500 acres.
ExxonMobil used the same technology that we've been talking about here today. This is on the far left. Again, it's a time-migrated data. You can see some steep dipping reflectors under the salt, but it's hard to image the actual salt sediment interface. In 2009, Exxon acquired a pre-stack depth-migrated data set. You can see the salt image is very crisp and clear on the north flank and under the salt on the south flank. And then finally, they acquired a reverse time-migrated section. You can see -- not only can you see the salt sediment interface, but you can see seismic reflectors very clearly. So the mapping and targeting of an exploratory well become much less risky.
Currently, the Merlin well is setting a liner, preparing to drill out and see these deeper targeted sections. By virtue of this AMI with ExxonMobil, we also now own the Vermillion 164 field. This field is located in Block 164. We have 100% interest in this block, and any hydrocarbons that are found in this area of the AMI can be tied back into this facility. We see resource potential here of 300 million barrels of oil equivalent. This resource potential rivals deepwater discoveries but is more attractive in many ways. One is that you have nearby producing facilities you can tie to and the cycle time from discovery to production is much shorter and much less expensive.
Now I'll go back to the resource pie chart where we see 2 billion barrels of oil potential. I'll show you the largest prospect that we have in the pre-Miocene section here in the Main Pass area. This is a pre-Miocene structure. The yellow box has outlined the acreage we hold. Some of this is producing, some of it's primary turned federal and some is state acreage. The structural closure here is shown in this white online. There's about 8,000 feet of structural closure on this feature. There's about 3,000 feet of structural closure on this feature.
Between the 2 of these features, we believe there's over 700 million barrels of resource potential. In the middle of this structural feature, the higher part, which is shown in red and yellow, there's a salt body and a fault system that brings the hydrocarbons from the source rock interval into the reservoir rock interval, not only at this level but also in the shallower levels. This is that east-west seismic line, and this is the map horizon from the map that you were just looking at, this dashed section. You can see we're not under the salt overhang here so the image is easier to image and clear to map. In this case, this is a small structure you saw on the left, the larger structure on the right. This system of faults and salt that run through this internal have migrated hydrocarbons into the shallower fields and have produced 289 million barrels of oil equivalent.
Back to the resource pie chart. I'm going to show an example in the -- in our Deep Miocene portion of our portfolio in the Grand Isle area. Earlier, I talked about a subsalt play in Grand Isle 16/18 located here. The feature on this map is this section here. It's not associated with the salt so we characterized this as Deep Miocene, although this well will target the Middle Miocene and also Lower Miocene section on this huge feature. We see about 300 million barrels of oil equivalent in this interval. There is 3,000 acres of closure, and there's 8,000 feet of untested section. This is the map horizon you see on the left. This is AA prime. This is the north to south seismic line, targeting those Middle Miocene age sands found in Heron and also targeting the Lower Miocene section here. The structure persists or a long section of rock.
So that concludes the presentation. We're here to answer your questions. And please use the microphone.
Could you just go to what you think you found so far at Heron and when could you have initial production?
I'll let Mr. Bordelon answer that.
Right now, we're just -- we're fishing up running a liner. We have some additional evaluation. We're running the BSP. We're going to finish up a salt proximity survey. At that point, Apache is going to move the well off to take care of some other operations at another field. In about 30 to 45 days, they expect to bring the well back on, and we're going to drill the #2 well, which will basically delineate the upper oil pays that were encountered in the well as part of a sizing process for the platform. The well is cased off with the liner, so we have the option at that point to go in and test the deeper sands again for additional sizing of the facility. After the #2 well, we will evaluate at that point. Once we look at the salt proximity data, if we want to drill yet a third well updip of this current location to look at the sands that we've encountered in the deeper section or do we want to drill off structure again but look at the deeper section. So we still have a little ways. We don't have any kind of reserve numbers put together at this point. It's still too premature to have those.
In past years -- for a number of years, in the breakout sessions, we've had substantial slides and stuff on the walls involving the ultra-deep. This marks the first year when you can't find it in any of the literature or anything else other than on a big map, the Gulf of Mexico. Why is that?
Right now, we're in a mode at the ultra-deep where we're about to complete 3 wells: Davy Jones #2 will be completed, rig will be on location in December. Lineham Creek is being -- the facilities and the casing has been set. Lineham Creek is a discovery, and Chevron is in the process with McMoRan and us designing the completion for that well. That should be the first quarter of next year when they start that completion. And after Davy Jones #2, the rig will go to Blackbeard West shallow. I guess, from a strategic standpoint, for the last 4 years, we've been learning a lot and getting all that information out to the investment community. We felt this is a time where it's time to sit back, let the wells do the talking and eventually, we'll turn those wells on and we'll have an update for you next year. But there's still a lot of excitement. We have other prospects we're going to be drilling next year. [indiscernible] is one of them. It's north of Lineham Creek and it's a really beautiful prospect and you'll hear more about it as the time comes on.
What do you view as the major uncertainties for these prospects working out or not? And then, kind of at what point do you know, hey, this is worth continuing to spend significant exploration capital on, or, hey, maybe we should dial back and spend the money on the core business because this isn't a great sort of return on capital looking for the stuff?
Well, I think that the primary risk in any of these kind of regional type of structural plays is reservoir quality and fluid type. So because these are salt features and we've seen deep oil production associated, the entire section of the Heron well, down to 16 7, all the base sands were oil. So we're encouraged by that. The well to the south had oil all the way down to approximately 19,000 feet. In Lake Washington, north of here, on the salt feature, there's oil production to 20,000 feet. So the maturation of the source rocks in close proximity to salt tends to give you the opportunity for an oilier section deep. But that's always an unknown. There generally is a mix of oil and gas, and in certain parts of the Gulf where the source rocks have been buried more deeply so that they're more mature, they become gasier. In this area of the Gulf, they've not been buried as deeply and there's a lot of salt in this section, which helps to cool or retard that maturation process. So we're hopeful that we will see liquids in these deep sections.
Sand distribution and thickness is always a concern. Anytime you're drilling deep exploratory well, whether it's a salt feature or not, but we've been very encouraged by the Heron well. And we know from regional studies -- let me go back to slide -- go back to Slide #6. We'll look at Slide #6. We know from regional sand distribution maps that the middle and lower Miocene depot centers are in this area of the Gulf. So we think the risk for deeper sands is not as great as it is in other areas. So we're very encouraged by the results of this well, and we think that these features in this part of the Gulf can be just as good or better. And we still have a lot more to learn from the Heron well. The offset will tell us a lot. And we're going to have to wait almost a year for the WAZ processing to be in-house to get a really clean image of not just this salt feature, but these other salt features that are identified as targets in the future. Any questions?
I know this is premature, but what's your best guess as to where the second Heron well is going to go?
Second Heron well is going to be drilled south of the first one. It's going to be drilled about 1,400 feet south of it, again, to try to delineate the shallower reservoirs that we penetrated in the #1 well, again, to try to help size up and get an idea of the lateral extent of the reservoirs, as well as the sand quality. We encountered over 100 feet of oil play in the first well. We've looked at the seismic section, and you could see the sands thickening, coming off structure, so we're very encouraged and optimistic that a lot of the sands that we did penetrate will get much thicker down dip.
Will you still be, if you look at it vertically, under the overhang?
Just a question on wide azimuth. I mean, I guess, you guys have seen wide azimuth from the South Tim area, and just curious as to what your thoughts are going to be on its application for the deeper stuff. I mean, do you think it's kind of a game changer or just an incremental help to the exploration process?
Actually, I'm glad you brought up the phrase game changer because from what we've seen so far in at least the Main Pass, Apache JV data, the quality of the data is better than anything I've ever seen. So I think that's what we're looking at. It certainly will be better than what we have now. We're just going to have to wait a little bit for that data to be processed. Now what we have in South Tim, we just have a limited amount of because that was a speculative survey, and we weren't able to control how the vendor distributed that to their potential clients. However, later this year, we're going to be outside their exclusivity period, so we'll be able to get some more data and get a better, wider look at our South Tim 21 field with that data. But so far, what we've seen with that data and what we expect with the Main Pass data is head and shoulders above anything we have now.
I'd like to add one more point while we have this slide up in front of you. The South Pass 62, if you look on the right side of that feature, that's a prospect called [indiscernible] that Apache also has. And we will probably wait again until the WAZ data is in because as you can see, it's clearly transparent at that point, pretty much like the Heron well was. But just to let you know, there are other prospects out there, that this is not a one-off type of situation with the Heron prospect. So we're pretty excited about the area. We think that, like Ross was saying, that the new data is going to really help us to image the salt sediment interface that's underneath the backside of these salt domes.
I guess just one more, as I have the mic in my hand. What's the advertise for risk in this program going forward? I mean, is this something you'll continue to look to bring partners into?
Since we own and operate 100% of the bulk of this acreage that we talked about today, it allows us the ability to leverage someone else into these prospects. So that's something, as a strategy, that we're looking at going forward so that we can better utilize our exploratory dollars.
John Daniel Schiller
Hi, everybody. I hope you had a good breakout room. What I thought it would be start with is I've got Jason and Jack up here. I know in the West Delta room, there was a little squeeze for time. So if you had some questions specific for them, go ahead and shout them out. We'll get those answered. And then the general questions for the executive team, we'll handle those, too. So have you all do it, but I know those, particularly the first group, didn't really get a lot of time for Q&A.
Yes, Joan? Hold on, we got the mic going somewhere. The only one in red.
Joan E. Lappin - Gramercy Capital Management Corp.
I guess, I don't know if I'm the only one that doesn't understand, and I was just given some explanation here from your compadres I'm seated with, about all of this water and -- that you're pushing through. Where does the water come from, where does -- how does that water get filtered? Where does it go afterward? How much does it -- the processing of all that water affect the cost of doing business, basically?
John Daniel Schiller
Okay. That's actually a great question. Let us start with the basics, okay? These big reservoirs, like at West Delta 73, where we have 4,000 acres of oil, that sand and that structure is actually 10 or 20 times bigger. So what we call the aquifer ratio to your reserves is 20:1, all right? So what I mean by that is you got oil at the top of this structure, everything else is filled with water. That's the way it's laid down. That's what fills out fogs, right? So as you pull out that oil, all your aquifer is doing is expanding. It doesn't necessarily have to be recharging. I mean, it's a lot bigger than what you're producing, you've got that kind of pressure behind it. And so that's what drives the water -- that drives the oil towards us. In terms of handling and processing, and the Gulf of Mexico is easy as far as to have rig, 2 ways of doing it. Some of our fields, we actually process it on the platform, put chemicals with [indiscernible] oil, clean up the water, put it back over board. And those samples are tested every day. You have a big case on that. You put the water in so you're looking for shade at any given time, and you make sure you put them back in saltwater that's actually less salinity than what's in the Gulf of Mexico to begin with. A large part of the Exxon production, actually since everything charged grand offshore-based water, oil and gas, we separate offshore, monitor, bring it back in, separate it again in Grand Isle, and there we put the water into injection wells. We've got 3. We only utilize 2 at any time. And again, remember there, it's a different environment. You have to bear the highlands, so you're injecting saltwater into an island that has no freshwater. They have to bring in freshwater because everything is saltwater. And so it's cheap. For us, it's relatively cheap. I mean, it's not like guys onshore shale plays that we get rid of water and pay it some of the couple of dollars a barrel and a lot of treatment. It's relatively cheap for us, much less than $0.50 a barrel.
Joan E. Lappin - Gramercy Capital Management Corp.
Since I still have this thing, the noticeably absent from anything in the book and all of that is the shallow water ultra-deep.
John Daniel Schiller
Joan E. Lappin - Gramercy Capital Management Corp.
It's like 3 years ago we were here and everybody was really excited about it, and now we're not even talking about it.
John Daniel Schiller
Right. We put the same amount of time into this as the value we're getting on our stock, but go ahead.
Joan E. Lappin - Gramercy Capital Management Corp.
Say it again? What? What?
John Daniel Schiller
We put the same time into this presentation as we're getting in our stock price, but go ahead.
Joan E. Lappin - Gramercy Capital Management Corp.
Well, but maybe those are directly related. And so the question is, I mean, have you given up? I know where we're going.
John Daniel Schiller
No, not at all. I just think we're at a spot right now that until we get back and start the completion at Davy Jones 2, which FCX talked about in their release yesterday, we'll go out there in December, probably start the actual completion in January, get Davy Jones 2 tested, Blackbeard West behind it tested. And we're going to get the Lineham Creek well on production in 2014, which is where there are a lot of excitement around the Yegua. We got good quarter, we analyzed it, but all the preliminary numbers say a lot of profitability in that rock. So that's kind of where we're focus. There's not -- I mean, there's not a lot to talk about right now, is the main issue. The plays are what they were...
Joan E. Lappin - Gramercy Capital Management Corp.
Do you still want to discord your interest in the shallow water ultra-deep?
John Daniel Schiller
We are looking to monetize a piece of the shallow water ultra-deep along with the exploration stuff that you saw, the deep structure you saw around some of our assets. We got all that in one pack and we're looking for someone to come in and put money into that exploration program like that. We're not getting rid of our interest in the ultra-deep.
Question. As it relates to -- you mentioned in the presentation, wanting to look at some assets around Southeast Asia and how the geography and sort of what you've uncovered mimic some of the Gulf of Mexico assets. Do you think that's a bit of a style drift because your expertise and the team is surbased in the Gulf of Mexico and your experience there? And more importantly, you also talked about that, if you were to go -- when you've identified the assets that CapEx for those needs would be self-funded, are you saying that you're mainly buying a working interest in existing projects? Can you sort of clarify what that potential move in Southeast Asia means?
John Daniel Schiller
Yes. [indiscernible] going international, is that what you're saying?
John Daniel Schiller
So we're not doing exploration international. We're buying exact type oilfield we've been buying at Gulf of Mexico. Big, existing oilfields, existing production facilities and with cash flow at day 1. So we go in there, and we do the same thing that we talked about in our part. We go in, we optimize production of gas, we go out bottlenecks. We make the operations themselves more efficient. And then we start deploying capital. And so it's a one step to get the production up and cash flow up, second step, CapEx. But none of those stuff we're talking about is in excess of 10% of our capital budget at any given year. And we're not talking about billion-dollar deals. We're talking about -- if we were to get 2 opportunities, we're looking at -- we're talking less than $200 million.
Hi, could you talk about where you are in your current stock buyback program and whether you would consider expanding that under your recently refinanced revolver?
John Daniel Schiller
Yes. Refinancing or doing what we did in revolver, the mix, the increase in the revolver is a critical part of the deal of stock buyback. And obviously, some assets is also a big part of that. We've been in a blackout. We're coming out of the blackout on October 30 once we get our earnings out there. And so, I think, then you'll see us start back into the market. We formulated any event the company is way understated. So I think you'll see us continue to buy. We're authorized for $250 million. We're less than halfway there, so we got a lot of room there over time to put the money to work.
John, you are talking about monetizing a piece of your -- or pieces or parts of the ultra-deep. Could you give us an example? You basically own, like 18%, a whole bunch of properties. Would you sell off something like England in total? Or would you sell off like 1/3?
John Daniel Schiller
Well, it's a total package deal. But the deal, if you looked in the proxy that McMoran-FCX merger, they gave a hypothetical joint venture description in there. That's a kind of structure we're talking about. So we give up 1/3 of our interest, someone pays us x amount of our ground, many we have for that interest. And they pay a promote on the drilling on 2 or 3 wells going forward. Those are the type of things we're looking at. So you get some money back from what you've already saw costs and you get some promotion going forward.
So you're not abandoning the ultra-deep or anything?
John Daniel Schiller
No. We like the ultra-deep. We just like making money off the oil right now a lot better. And so -- and it's tangible, we can point to all opportunities. There's a lot of things going on in ultra-deep. [indiscernible] leasing right now. I give general direction that's onshore. We think we have some really neat prospects, but we're in the middle of lease and big equity position, so we're not allowed to tell you guys about it.
Okay, you like ultra-deep and...
John Daniel Schiller
I won't blame you for ducking this, but if Jim Bob likes the ultra-deep, but Jim Flores didn't like the ultra-deep, what's the...
John Daniel Schiller
So far, you made a statement. [indiscernible]
So how do you think that's going to play out?
John Daniel Schiller
I think it plays out the same way either way. I think Jim Flores -- get the mic away from Rick. Put him in the penalty box. Look, I worked for Jim Flores. Jim Flores has a bunch of good technical guys. We've worked with him in the past. Dan Willis has done this. The project is a lot [indiscernible] then we made the decision to get out back after Macondo. So there's certainly a whole lot more about some of the things going on in the Gulf, they were all about technical. So I wouldn't jump to the statement that Jim Flores doesn't like it. I think he wants to make money, and if we're sure it's making money, he'll put capital to it. Now do I think we're going to get 5 more exploration wells without success? No. I think we'll drill 2 more exploration wells, and if we're not having success, we're not bringing them to production, we're through with the project. But I wouldn't put that on Jim. I'd put that on me, too.
My question is about sort of what stock you're trading right now versus your estimates of NAV. What the market is kind of telling you is that you guys need to execute and sort of block and tackle versus adding reserves. How do you think about moving into some acquisition in Asia, which would sort of increase your execution risks? And what really do I think for that sort of either moving other rig into the Gulf or repurchasing shares? So how do you view when your stock is trading at like $18 or $20 a barrel? What is something in Asia have to be for you to go out and do that versus repurchasing shares?
John Daniel Schiller
I think, first, you have to see what the economics looks like on the Southeast Asia deal. There's a lot of oil in the ground. Again, it's what we do good. You've seen it, you've seen 80% increase on reserves since we acquired the other fields. This won't be any different. We're coming behind the same type of operators. We're going to do what we need to do for our shareholders. We do think that the only way to get a multiple increase is a shale that you have a multitude of repeatable opportunities that we will come back next year at West Delta 747, West Delta 30, 747 is a new stop. West Delta 73 continues on what it's doing, and we start drilling South Pass 49, then you really start understanding that we're a different altering machine. I've tried to explain that over the years, people don't believe me. There's never been an independent to have 70% of oil production with this very major field. They were controlled by the majors. And so it's a unique set of opportunities we have, as Jason wrapped up at West Delta 73. I mean, it was West Delta 30. This is not your normal independent oil company in the Gulf of Mexico, and our job is to convince you. We tell you, now we got to show you the results and convince you of it so that we get the right multiple.
What that just involves, focusing on the Gulf of Mexico near term over the next 1 to 2 years versus trying to go out to Asia?
John Daniel Schiller
There's only so much activity you can do in the Gulf of Mexico, right? And there's nothing big -- I mean you guys want to talk about quarter by quarter. We've got to run our company and our board on years by years. And the growth for us has got to be somewhere else. We're willing to grow the assets we have, but assets like that aren't coming available. Chevron would love to have Bay Marchand. What's your guess, Jason, 5 years? Yes, Edward [ph]? I mean, once Chevron makes a huge amount of production in the deepwater, maybe somebody in California says, why we keep Bay Marchand when they put it up for market? But it's not going to be next year or 2 years or 3 years from now. So we got to keep the card loaded, and those opportunities -- it's identical geology, it's the same type production mechanisms and everything else that we're used to doing, so it makes sense.
Can we have an estimate for production CAGR for the next 2 years for all the operated fields? We got West Delta 73 and 30 today.
John Daniel Schiller
Actually, in the projection slide, there's about 11% CAGR on the reserve section.
In totals, but how do that break out amongst the different fields?
John Daniel Schiller
We're not going to get into that detail. I mean, obviously, [indiscernible] rig and drilling, right, West Delta 73 and West Delta 30 and so around Main Pass 61. Those 3 are the big fields that we showed you on the capital efficiency. Then we have a little contribution over that 3 years from South Tim 21 and South Pass 49. But those 5 big oilfields are what's driving all of your growth.
John, the $11 million well course for horizontal versus vertical, 2-part question to that. A, are you already at the $11 million? And B, other than just being a short lateral thousand feet, why is it only a $0.5 million more than the vertical?
John Daniel Schiller
Well, look, that's a tough comparison to make, okay? That is what we're talking about. The recent economics is a little bit different. In other terms, we're talking about a threefold increase over what we get from one sand versus what we get from the horizontal, okay? But at same time, [indiscernible]of the wells, we've set up multiple completions in multiple sands, okay? And so those completions cost a lot more money. The simplest completion we have is a gravel pack. We're in and out in 7 days. A typical vertical well for us, we were taking 30 days to complete. That's where a lot of the cost came from, all right? So it's not exactly an apples-to-apples comparison. And it's not an obvious jump to solution that every well should be drilled horizontal. We take that attitude and we look at it that way, but as Jason said at the last meeting, not every well's geometry, not every reservoir's geometry is set up. Main Pass, we drew a lot of high-angled wells because of the way the amplitudes are, because of the way that the sands are. We're better off doing that than trying to get horizontal in one of those sands. That's too tough a well to drill.
Is that $11 million something you're achieving now or is it more of a target, or have it...
John Daniel Schiller
Yes, I think what I'll do next time, we're going to discuss -- we're change that slide. We're going to show you also how much of that is the slot recovery because that's really where the variance is in those cost from a low end to high end, is our slot recovery because we're reclaiming slots and starting over. So we got to pull all cases and all the way up and start with a new drive pipe before we drill the well. And sometimes, we get that done for $1 million, sometimes we get it done for $3 million. If you just focus on the actual drilling and the well, we're probably less than 10% variance between the wells. And it's a sad number. I think you're going to see $11 million keep going down, though. I mean, the rigs are getting really efficient at drilling these wells, and the teams are getting better at directing it and serving sands. Everybody is a little bit better on making sure we draw that lateral court. And elimination of the pilot holes is worth $1 million.
Just a couple of questions on costs. Do you see any changes in terms of how much it's going to cost to drill the particular wells in the various areas that you're at? And then secondly, if you look at the forward curve, the price of oil declines, what -- about mid-80s, there about, some couple of years out. How do you see the economics if that forward curve is realized? Are there any areas where you would choose to redeploy capital? Are there any areas you'd like to put more capital in, take capital out? Can you sort of address where you see the future?
John Daniel Schiller
Yes. Two things, [indiscernible] it's been very interesting last 2 years. Rig rates have been more or less stable. We signed some of our long-term rigs up for their third long-term contract. Never done that in our history. Mainly, because rig guys are really going to predict the top of the market, and they're usually looking out on permits to drill. And what's happened in this, and it's the first time we've had one in the Gulf in 35 years, is it's being driven a lot by workovers and rig completion. And you can't see those permits out there in the future. They're not there as a leading indicator for our rigs are typically priced off of. And so the way the workover market works, we may have several platforms right now with one well ready to be worked over, but we won't move the rig on until we lose 2 more wells, then we got 3 wells, the economics works a bit for mobilizing rig and things like that. And then all of a sudden, we're on the market looking for rig. And so that's what's happening in the rig market right now. The majors have realized $100 oil does when they're running rigs that didn't run before. Chevron, we know you've made you laugh, buy they're running rigs, the big independents are running rigs. So I think it's a number we can live at very nice. It's nowhere near the full high that they got to when gas was reaping at $8. Across the other question which was...
John Daniel Schiller
What was your second question?
John Daniel Schiller
Of future price, right. So we got a lot of base case economics at $65 flat, $80 flat. And we're still generating over 1 PI on these projects. Remember, we're making 5 right now at West Delta. So those -- do we shut down some or no? Yes, maybe at $70 oil consistently, we have to reevaluate and redeploy. But between now and then, that's still the best use of our capital in terms of the kind of returns we get. Joan?
Joan E. Lappin - Gramercy Capital Management Corp.
Well, it wouldn't be the Waldorf and we wouldn't be meeting here if I didn't ask about Crete.
John Daniel Schiller
About Crete? It's a great story in Crete. So it doesn't get drilled, but we've leased that -- we have to wait the lease -- the open lease. And while Chevron was shooting the Bay Marchand shoot, the gave the global geophysics guys -- the global geophysics guys excluded our South 1021 block and said, we want to be able to sell that to Energy XXI day 1. And so they were able to do that. We didn't own that other block at the time, and Chevron has refused to let them give us the data early, so we have to wait 6 months for the data to be able to go public before we buy the block that Crete is under. So it's South 1021 proper. We've seen what the WAZ, the wide azimuth in Seismic does for us. We've seen some up dip locations start developing. We haven't seen Crete yet. We haven't seen it on the wide azimuth. I mean, remember, that's why we postponed shoot, when we had to wait 6 months for the shoot day, which is going to be a couple more -- when?
John Daniel Schiller
December. So we'll get the data in December and we'll start looking at it. And by spring, we'll have some sense what it looks like and then if anything changed on the prospect.
Joan E. Lappin - Gramercy Capital Management Corp.
[indiscernible] auction after that is what merge?
John Daniel Schiller
No, we already have the block now.
Joan E. Lappin - Gramercy Capital Management Corp.
You have it now?
John Daniel Schiller
Yes, the reason it couldn't wait earlier was it was open, and we had to wait for the Macondo to work itself through before we had to lease sell.
Joan E. Lappin - Gramercy Capital Management Corp.
So you own it and now, in the next -- by the end of this quarter, you need to drill the hole.
John Daniel Schiller
We should have the data. Well, we'll have the data by the end of this quarter. There's one more quarter to analyze it.
Joan E. Lappin - Gramercy Capital Management Corp.
And these other prospects that you have, is this still as exciting as you thought it was 3 years ago?
John Daniel Schiller
Yes, and probably even more exciting. One of the things we talked about in the South playroom was, at Heron now, we got oil in 16 and 7. And the South is clearly keeping the temperatures down and the reservoirs are getting us deeper and deeper well. So our creeks as we look at all the data, we feel even better about having more oil and less gas than when we were potentially looking at it 3 years ago. No more questions?
Quick question on the West Delta stuff. West Delta 73, I mean, you guys are in a nice kind of run rate of IPs in the 1,000, 2,000 barrel a day range. What kind of expectations should we have for the horizontal program at West Delta 30 in terms of rates?
John Daniel Schiller
Well, look, let me put it this way for you. We got to get some wells down. Theoretically, we can have better rates there than what we've seen. Jason was talking about the specific numbers, a lot of processes in the mid-30s. Water -- oil saturations start where there's water saturation, rig it more 10%. So you got a whole lot of oil in that rock. That's why he talks about prolific the way he does. So when you run those numbers and you put just a little draw down on it, it's very easy to get 2,000 to 3,000 barrel a day rate. We're doing a lot of the of the balances and needs done a lot of rate coming out as we've already drilled. We think we're starting to understand the really good wells versus the just average wells and what's going on. If what we think happen is right, then it's not an issue at West Delta 30 at all because there's strong water drive there. There's not any sort of gas capture worry about you're going to be in all reservoirs. So we can get some great rates, but let us just see where Marlin is similar to West Delta 73 and all the number right now.
All right, Mike's got a question. He's going to ask the last question unless it spurs more activity with this question.
This is for Ben. You got 5 really big fields out of the top biggest fields in the Gulf of Mexico. Do you have anything in your inventory you're drilling right now that you think has the potential for joining that 5 as one of the biggest fields in the Gulf?
Outside of those 5 fields?
Well, our Heron prospects, our Vermillion prospects, they both have the potential to reach that level depending on what we find there. And Heron is very, very encouraging already. And as we drill more wells, we should uncover more data. Vermillion well, as we get multiple targets going there and we also have multiple prospects on that 11 block joint venture. We have 7 different prospects to drill. Pendragon being one, Merlin, Noevir and we got several other ones. So yes, those 2 exploration prospects not being as a prove up, they can very easily move into that kind of category.
John Daniel Schiller
All right. I want to thank everybody for coming out. We're going to go have lunch, and everybody will be available for some one-on-one time. So come join us across the hall for lunch. Thanks for coming this morning.
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