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Energy XXI (Bermuda) Limited (EXXI)

Q1 2013 Earnings Call

November 07, 2012 10:00 am ET

Executives

Stewart Lawrence - Vice President of Investor Relations and Communications

John Daniel Schiller - Chairman and Chief Executive Officer

David West Griffin - Chief Financial Officer

Analysts

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Adam Duarte

Joseph Patrick Magner - Macquarie Research

Joan E. Lappin - Gramercy Capital Management Corp.

Operator

Good day, ladies and gentlemen, and welcome to the Energy XXI First Quarter 2013 Earnings Conference Call. [Operator Instructions] As a reminder, this call may be recorded. I would now like to introduce your host for today's conference, Stewart Lawrence, Vice President of Investor Relations. Sir, you may begin.

Stewart Lawrence

Thank you, Sam. Welcome to the call, everyone. Presenting today is John Schiller, Chairman and CEO; and West Griffin, Chief Financial Officer. We'll be available to answer your questions at the end of the call.

Before we get started, I need to remind everyone that our remarks today, including answers to your questions, include statements that we believe to be forward-looking statements. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include, among others, matters described in our earnings release issued today and our public filings.

We disclaim any obligation to update these forward-looking statements. While the company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance. Our drilling schedules, capital plans and other factors may cause our results to differ materially. I urge you to read our 10-K and the latest 10-Q to become better familiar with these risks and our company.

Now I'll turn the call over to John.

John Daniel Schiller

Thanks, Stewart. Good morning, everyone. Our first quarter financials were released this morning.

Consistent with our preannouncement after Hurricane Isaac, production averaged 37,300 barrels of oil equivalent a day for the quarter. Looking at the quarter and the production in details, 70% of the production was oil, up from 68% the previous quarter. More than 93% of our prehedged revenues were from oil. Crude was 92% of the reported oil volume realized on $107 a barrel. The other 8% was NGLs at $35 a barrel, taking a combined average price of $101 a barrel.

Hurricanes captured most of the headlines recently, but the excitement for Energy XXI has been the launch of a horizontal drilling program, as well as the high-impact potential of our Vermilion joint venture with Exxon and our ultra-deep program with McMoRan. Each of these programs hold the potential to more than double our current reserve base and each has a very different risk profile.

Combined, we believe Energy XXI has a well-balanced organic growth program in place. We've come a long way from original acquisition-driven growth strategy that we started with 7 years ago. I'll go into more details on these programs after West discusses financial results. And with that, I'll turn the call over to him. West?

David West Griffin

Thanks, John. Let's review the quarter, starting with volumes. As John mentioned, we averaged 37,300 barrels a day for the quarter. The hurricane deferred about 5,700 barrels a day for the quarter. Repairs to third-party pipelines account for another 1,500 barrels a day of shut-in production. All of those volumes are back online.

At West Delta, one of our pipelines needed to be replaced and water handling systems were shut-in for upgrades, costing us another 300 barrels a day last quarter. West Delta should be back up to full speed in the next couple of weeks, resulting in about a 1,500 barrel a day improvement in our production. As we stated in today's release, current production is about 46,000 barrels a day. And since October 1, we have averaged approximately 45,000 barrels a day. John will get into more detail on the production ramp in a few minutes.

Turning to lease operating expense. Total LOE was down against the prior quarter due primarily to reduced workover expenses. This was offset by higher direct LOE, due mostly to the other operational costs associated with the storm. On a per BOE basis, the deferred production clearly caused the numbers to be higher than normal. Numbers will come back in line as production returns to normal, and we'll see improvements as we ramp up production during the year.

Finally, taking a look at our effective tax rate this fiscal year, we've increased it to 37% due to exhausting prior period valuation allowances. On a cash basis, we expect to pay a modest amount of alternative minimum tax and withholding tax. In total, this fiscal year, we expect cash taxes to be in the $10 million to $12 million range.

Now let's turn the call back to John to update our operations.

John Daniel Schiller

Thanks, West. Let's begin by looking at where we are in the capital program and how we're reallocating the CapEx to maintain our $700 million target.

With the addition of the joint venture wells at Vermilion, we have moved more capital into exploration and specifically in the more oil-focused projects that can have a larger impact on reserves and future production, not to mention value. The volume impact of that combined with a higher-than-budgeted downtime seen in the first quarter takes our expected full year volumes down by about 6,000 barrels of oil equivalent a day, as we indicated a few weeks ago. That would leave us with a very healthy expected volume growth rate in addition to the better prospects for reserve growth. Providing a bit more detail around our fiscal 2013 drilling program, we show the wells here by field, including 13 more horizontal locations and 3 key exploration wells. The oil waiting [ph] is clear.

On Slide #9, we show you directionally our future growth profile, what we expect the drilling program to deliver through the end of fiscal 2013. The growth wedge is primarily driven by the horizontal program, with a fairly steady ramp-up from where we are today. So let's talk in more detail of that growth wedge, starting with our initial results from the horizontal program.

Big Sky 2, our first horizontal, was a big success at 3,000 barrels of oil equivalent a day. The IP rate easily outpaced the best horizontal well drilled back in the field in the mid- to late 90s. First month production averaged 2,000 barrels of oil equivalent a day. We'll continue to monitor that well to better model future production growth for our horizontals. Everything we're seeing so far is positive.

Weimer was our second horizontal well in the West Delta field, and this well targeted the deeper sand, the F-45, and was completed with 175-foot horizontal section, with initial production of 1,800 barrels of oil per day. The rig has now moved on to Hyden, which is our third horizontal well on West Delta 73, and we should have the pilot hole down by this weekend.

That highlights a question we get a lot: What do we need to make horizontal wells work offshore? The primary answer is that geology is important. Optimally, we need large fills with large reservoirs to get the kind of results we're looking from for horizontals. It's all about the kh. We have plenty of permeability. What we're doing is extending our h by drilling horizontal wells anywhere from 500 to 1,000 feet and increasing our ultimate recovery. And that's the key here. While rates are important, what really is -- makes horizontal wells work in the Gulf of Mexico is your increase and your ultimate recovery per well, and obviously your value that's associated with the CapEx you spend on those wells.

Slide 10 shows the initial review of our big fields, where we have identified between 50 to 85 potential horizontal locations. This already represents a multiple-year horizontal drilling schedule, and we've just begun the evaluation process. So horizontal oil drilling should dominate our program over the next few years. Adding to this low-risk drilling inventory, we also have a growing list of core exploration opportunities that offer big reserve growth potential.

First on the list is our Vermilion joint venture with ExxonMobil, where our first well will test a large target. The rig is set to arrive tomorrow, and we'll begin drilling within the week. We have a 2-well commitment to the joint venture, paying 100% on 2 exploration wells that earn a 50% working interest in the entire 54,000-plus acre joint venture area. After that, we're straight up 50-50 on our interest and share costs, and we continue to operate.

Within the joint venture on the south side of this salt dome, there's 7 identified prospect areas that hold world-class exploration potential, all on the shallow water shelf. The first well is Pendragon, which targets about a dozen potential sands ranging from depths of 7,000 to 16,000-foot TVD. The second well is most likely going to be Merlin with nearly twice as many potential sands. This is a truly unique opportunity. Not only are these world-class targets in the region left for dead, but from the signing of this deal, it will be only a few months before we test the first prospect. And if successful, we can have it on commercial production shortly thereafter, where the first well's flowing through existing facility we own 100% and operate on the north side of the salt dome.

That takes us to the ultra-deep program with McMoRan. As you saw today, Davy Jones #1 is very near the completion. We're currently nippling down the BOPs. Next step will be to nipple up the tree, and we expect the flow test to occur during the next week. Now Blackbeard West, we have extended our TD there to 25,500 feet and we're currently at 24,000 feet -- 24,500 feet. When we get to TD, we will then run a full suite of logs to evaluate everything we have in the hole. At the McMoRan-operated Lomond North, we're drilling ahead at 9,000 feet and at Lineham Creek, we're at 24,450 feet, drilling ahead to our next casing point, which should come in around 26,000 feet. So that's kind of it operationally.

Let me make a couple of statements for you guys. The elections occurred, the world goes on. Obviously, we think we're in an environment where we can continue with what we do. We've learned to live with the regulatory environment we're in. And things move forward, we have no delays because of that. Second, I want to mention because of football season and my Aggies are 7-2 -- as everybody knows, we've got a little big game this weekend. The football world lost a great coach this morning, Coach Royal passed away. He meant a lot to the world of football, particularly to the state of Texas. And my heart goes out to my friend, Jim Bob, who lost a great mentor today.

So thanks for joining us today and for your interest in Energy XXI. Last month, we celebrated our seventh anniversary and it's been a good run for us. With the portfolio we've created and the drilling program in front of us, we're more confident than ever that the future will be every bit as exciting as the past. We look forward to reporting results of our efforts as we grow production double-digitally through the development program and add meaningfully to our reserve base through our high-impact exploration while we continue to generate a good solid amount of free cash flow.

So thanks for joining us for the ride. And, operator, let's go ahead and open it up to Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from David Deckelbaum of KeyBanc.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

I'm curious to know, how do we think about this drilling times and completion just from spud to sales on sort of a generic horizontal well?

John Daniel Schiller

Yes. David, I think the thing about the horizontal wells is the completions are very short. We'd literally, from the time we TD the well with open hole, we're about 8 days to production. Yes. So I think we're going to probably average on a typical well for us somewhere around 45 days from the time we drill it until we have first production.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

And the first 3 so far, what are you seeing in the difference of CapEx versus what you would've done if you had it completed vertically?

John Daniel Schiller

We're well within the 15% incremental cost that we thought we would see. Actually, all 3 -- or 2 of the 3 wells so far, beat the AFBs [ph] we had for them. We've got a rig that's running really good for us now, the Nabors rig has been out there for a while. This is the seventh well we're drilling with it. They've gotten very smooth in their operations, and so we're moving ahead quickly. And those dates, those timeframes include, remember, drilling the pilot hole, which I think really going to be [indiscernible] from spud to pilot hole TD this weekend, probably 12 days, 14 days. So you'll see we're moving pretty quickly on these wells, particularly in the West Delta area.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Great. And then last one if I might. You talked about 50 to 85 horizontal locations that you've identified so far. You also remarked that you guys have kind of just begun that process. Are those 50 to 85 more or less coming out of a minority of your fields? Or is it across the entire program? And realistically, how long do you think it could take to have a comprehensive evaluation of all of the potential locations across your total portfolio?

John Daniel Schiller

Yes. I think, David, those primarily come from 4 major oilfields. As you heard me mention, those are the primary targets right now. I don't know that we're going to do anything a lot more extensive. We're going to continue to model some of the reservoirs as we have at West Delta and as we have at Main Pass 61. We're going to do a second reservoir at West Delta right now. We already started that process with Schlumberger. So all of those things will continue to feed us more data. I think the steps of where we step out and really start looking for [indiscernible] sands that haven't had as good recovery or for pressure depletion areas, where we have to put some water injection in, we'd still look at that. But I wouldn't tell you that's a near-term number you're going to hear us talk about.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. And then just one quick last one. If you guys targeted 1 million barrel EUR for sort of a bogey for some of these horizontals. And the first 3 have certainly all come in line with that. What do you think you're going to get credit for in your reserve report next June?

John Daniel Schiller

That's a great last question, Dave. I think we're going to get credit for whatever we produce between now and June for sure. And then after that, our friend at [indiscernible] will probably give us some of it. I think the numbers we're telling you will clearly all go in the 3P category. I think we feel pretty good about that. I think we're going to have to get down the road a little bit on the declines to see what kind of type curve modeling we can do on them. I would tell you I think the initial impact is going to be, let's just say we drill a PUD that [indiscernible] has given us 7,000 barrels on. And so we think it's going to make 1.2 million, 1.5 million. We're probably going to start somewhere in between the 2 of those to book it, and then probably over the next year to get to the number.

Operator

Our next question comes from Duane Grubert of Susquehanna Financials.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

John, could you talk to us a little bit about how the teams work together on the JV? Are you guys having more engineering and geologic input than we might suspect? Or how does that work?

John Daniel Schiller

Yes. Duane, it's a another great question. It's a little different in that -- we had a closing done the other night with the Exxon group that generated this idea and they started on it...

David West Griffin

4 years ago.

John Daniel Schiller

4 years ago, they identified it, started putting it together, 3D. It was on the edge of a shoot they had. So they've been working a long time. They clearly have a lot of knowledge. Our guys are up to speed. We see what they see on seismic. We have the reprocessed seismic, but I will tell you early on that the locations we drill are going to be highly driven by the technical expertise of Exxon and what their people have looked at over the last 4 years. I think where we'll start stepping in more will be as we drill development wells and how we go about doing the development. But I think the first couple of exploration wells are pretty well set by the work that Exxon has done.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay. And then back to the horizontal stuff. You've got a nice program, we can all make the leap of faith that every well is going to work. But you probably in the back of your mind think, "Well, that's a perfect world." What risk is there? Is it about depletion in the field? Or is it about completion of the well? Or what would be the thing that might make a negative surprise somewhere along the horizontal wells in your completion program?

John Daniel Schiller

Yes. I mean, I think the thing you have to understand, it's a little bit different. We were talking about this at our board meeting yesterday. The guys that drill shale plays, they drill these mile-long horizontals, laterals because they're trying to increase their permeability, all right? It's not so much about dates, they need more fractures, they need more area to frac to increase their permeability. We have all the permeability we need. This play for the Gulf of Mexico is about having a 500- to 1,000-foot lateral out there and increase your ultimate recovery by just moving a lot more fluid. And when you look at the data we continue to see across all our major oil reservoirs, which is evidenced time and time again both in reservoir simulation and actual log work of recoveries in excess of 70% of oil in place, the way you get there is by putting these horizontals in, moving big volumes, 3,000 to 4,000 barrels of fluid a day. And even if it's only 10% or 15% oil, it's going to be there with you for a long period of time. And so that's the tough part right now in terms of projecting things is some of the wells are going to come in that way. Some of the wells, we're going to play a little on the edge and we're going to end up making 500 barrels of oil a day and 2,500 barrels of water from day 1. But they do it for a long period of time, so they make us a tremendous present value return on our investment. And so that's kind of how you're doing it. And so the impact really is do you get 100% clean oil on every well you drill? Do you get 100% clean oil on half of your wells and the other half you push further down into the reservoirs and you're willing to take 1,000 barrels of oil a day or 500 barrels of oil a day to start with but you know that, that's going to stay with you for a long period of time? And that's all the stuff. I mean, we can look at all the wells. We know we're going to have all those type of things. I would tell you early on, obviously, we're going to try to stay near the top on some of these reservoirs and get good drainage. You've heard me talk about DrO, the well we're drilling out at Grand Isle, help me. That well is sitting at the top of a reservoir that's already produced 21 million barrels of oil and only 6 million barrels of water. We know we have, from pulsed neutron logs, like a 300- or 400-foot oil column remaining there. That can be really nice, clean oil completion, it should be. So they're not all going to be like that. Some will be more like West Delta, where we're sitting on top of the shallow, where 20 feet of oil on top 100-foot of water on the sand or 20 foot of water on the sand. And so we're going to make water kind of quick, but we're still going to make a lot of oil. And that's what it's all about. It's about the ultimate recovery, not about that initial flow rate as much.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay. That's helpful. And then finally, a different topic altogether. When you instituted your dividend from a position of strength, commodities were a little bit stronger and so forth. How are you thinking about the trajectory of the dividend, how you would make a decision to increase it, for example? And maybe a comment also on philosophy about share buybacks and, of course, debt deleverage over time.

John Daniel Schiller

Sure. The dividends, we intentionally set in an area where we felt we could grow it and continue to grow it going forward. I think that what you'll see is that's something we'll try and do on a yearly basis, so we're getting ready to pay our third one. As we pay the fourth one, I'd be looking at things staying strong and we do what we're doing, that we'll look to increase that dividend and continue to make it more meaningful. I continue to tell you that share buyback for a company like ours, that we're always -- while we have a very strong organic growth opportunity with some of the things we have going on, we're going to continue to evaluate acquisition opportunities where we think we can improve things dramatically with the team we have. And so I have a harder time buying back shares where it might turn right back around and be offered a $2 billion acquisition opportunity that we would issue some equity back around or something. So that's not high on our list. We've looked long and hard. West probably had every banker in existence come talk to him about doing bonds versus our debt level, on our existing debt, and the economics just make no sense. When you have to talk about 8.5-year payouts in order to do a bond deal, because of what we can give above today, present value-wise, it's kind of hard to get excited right now when your debt's not callable until December 2014.

Operator

Our next question comes from Michael Glick of Johnson Rice.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Just a quick question on production. How should we think about the oil-NGL split as you move through the years? Is that 8% a good number to use? And then looking at the production ramp itself, how do we look at exploration being factored into that growth profile?

John Daniel Schiller

Well, the first one on NGL. I think, 92% of our production overall was oil this year -- this quarter. I think we're going to stay above 90% absent us telling you we've brought on a really big gas well that has a big impact on it. The reality is some of our fall-off comes from gas wells, like Winters and all that were giving us pretty good NGLs. So if anything, it's going the other way right now until we tell you that we drilled a really big gas well at Pintail or Laphroaig or something like that. Overall production and impacts from the exploration, I think we've got to see where we have success, and then we can talk about it. The good news, as you guys have noticed, our rates are fairly predictable. We know as soon as we see a log, pretty good idea what kind of flow rates we're going to make and a pretty good idea of the size of the reserves. Every once in a while, you get a surprise. But for the most part, it's predictable. So let's just start drilling a couple of good wells, and it'd be a good problem to have as we try and tell you what we've got going forward.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

All right. And then at Pendragon, how does that prospect compare to the 6 other prospects in the JV in terms of size?

John Daniel Schiller

It's not the largest. The largest is actually Merlin. Merlin's about 21 potential sands and twice as big as most likely reserves, or three times as most likely reserves as Pendragon. But Pendragon has 2 things. It's the shortest lease exploration left, a; and b, we like the way that trap [ph] sets up. We think if Pendragon works, Merlin is almost a given. So if Pendragon doesn't work, we probably don't drill Merlin next. We're probably going to drill another target while we evaluate why Pendragon wouldn't have worked.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

And then shifting to horizontals. I mean, it's probably too early. But just in terms of the initial production from Big Sky, how has that kind of shaken out compared to some of the historic Exxon wells that had successful completions?

John Daniel Schiller

That field in particular, there were 9 horizontal wells drilled by Exxon, 3 were completed the way we just completed Big Sky and Weimer. The other 6 utilized prepacked screen technology. And so when you look at the 3 that were done the way we've done them, those are the 3 that are still on production 15 years later. Their best IP was 800 barrels of oil a day, and yet they're all going to make an excess of 2 million barrels of oil. So we feel pretty good when you look back at that. And in fact, that we're 12 years later in the production cycle in the field that we're getting the kind of results we're getting.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Then last one for me, just more on the horizontals. I mean, when you guys talk about 1 million barrel-plus EURs, what kind of well life are you assuming in that EUR?

John Daniel Schiller

Yes. I mean, it's in the same life of what you've seen so far. They're going to be 15-year-plus. We had -- at 1 million barrels, we're kind of hedging, so I wouldn't say 1 million barrels, 15 years. I would tell you we're going to get 2 million barrels out of them and we're going to be 15 to 20 years. 1 million barrels would probably come out of the ground inside of 10 years.

Operator

Our next question comes from Richard Tullis of Capital One.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

John, in keeping with that same line of discussion on horizontals, what do you look for in production declines from individual wells and the horizontals, say, years 2 through 4 versus the verticals?

John Daniel Schiller

Yes. So I think what you see -- and Richard, we're working on a slide that we'd probably bring out to give you some sense of the horizontal ramps. But if you go back and think about how we show you when we used to go into some of the details of our production base, how our wells that have been on production for more than 3 years, average about a 14% decline with regards to the oil wells, I think what you'll see is that decline continues to shallow out for the horizontal wells. So that 4 or 5 years from now, our base production should be having a

decline rate coming closer to 10% instead of 14%. That's all results of what the horizontal wells look like a couple of years down the road.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Looking at fiscal year '13 guidance and then using the Page 7 in the updated presentation, is your new guidance for the year 52,000 to 56,000 barrels a day?

John Daniel Schiller

Yes, I'd say that's in the right range. I hesitate only because I'm thinking more in terms of oil these days. But yes, if you're looking at where we are and you take out the 6,000, that's where it puts you.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

The net CapEx associated with the 7 gas wells deferred in the original budget, how does that compare to the new oil projects that were added?

John Daniel Schiller

Yes, so that's where I was starting to go. I'm glad you asked that question. So what it means is, while we're lowering the overall production, our percent of oil starts climbing into the, sort of, 73% maybe even 74% range, depending on what some of these wells do. So it's the classic case that we've talked about all along, which we lower production guidance but if we look at our EBITDA and cash flows for the year, they continue to be outpacing what we had budgeted for the year.

I was just going to say, it's really -- we had a long talk about this in our board meeting. It's really hard to explain to guys like us that have been around for 30 years and you never really worried about drilling an oil well versus a gas well. You were just sort of looking at how you made the most money per dollar invested. And today, with the economics where they are, it's just, you really can't generate very many gas projects that can give you the kind of results you get from your oil wells. So it's really forced when you're lucky enough like us to have an inventory of opportunities that are heavily dominated by oil, it really forces you to -- continuously to look at your portfolio and go, well, yes, I can go drill that slam dunk gas well, but why would I when I make the kind of returns I make off the oil wells? And so every time we make one of these decisions, and we were blessed by doing the Exxon join venture so that we had some more oil exploration opportunities, it becomes a slam dunk versus giving up some gas volumes to get oil volumes with a lot more potential value.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Finally, with the $194 million spent in the first quarter of the fiscal year, how do you see the CapEx kind of flowing for the remainder?

David West Griffin

We actually see it probably ramping up a little bit more this quarter and then it starts slowing in the third quarter, Richard. And then the fourth quarter, we'll be -- I think we're a quarter away from getting there. But if we see the results we think we're going to see in the horizontals, if we have some success at the Exxon joint venture, I think you'll see -- we've been talking about the last month that with the addition of Antonio and rearranging our technical staff so that our guys under Tom O'Donnell are 100% focused, on 100% operated opportunities. I think you'll see that number kind of move up in the fourth quarter if we continue to do stuff. We've kind of raised -- what I'll call our maximum capital efficiency expenditure rate to about $800 million, we think, with the changes we've made. And so when you put all that together, I think you will see it slow down a little bit in the third quarter but then will continue at that pace in the fourth quarter, everything being equal to where we are today, commodity prices and everything else.

Operator

Our next question comes from Andrew Coleman of Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Just thinking about the 52,000 barrels a day of production capacity, I guess, what do you have on cap, I guess, to expand that, as it looks like you'll kind of be there when you hit the 6 mb/d back online here next week or so?

John Daniel Schiller

Yes. I mean, clearly, bringing on the production we have shut in is going to get us a long way there. The next series of horizontal wells can do a lot for us. As I mentioned, Andrew, when you look up the setup, for DrO that can be a really good well for us and then we go from there. But we put numbers out there that we feel very confident we're going to make and short natural disasters and things like that, we should be there.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. And then thinking about, I guess, we'll hit the favorite subject of the day, the horizontal wells, I guess what's your tubing constrain limit? Could you go with longer laterals to try to get the additional rate and have smaller drawdown?

John Daniel Schiller

Yes. I mean those are the sort of things we're looking at, Andrew. We're having a very little drawdown based on our early models. I mean, I'm talking 5 and 10 pounds of drawdown across each horizontal packs. So rate really isn't our issue. What we're looking at harder right now is just, do we bring the wells on a little gentler and let them ramp up over time, those type of things, to see how we maximize our 100% oil flow, if you will, before we have to deal with water. I don't think we'll go further than 1,000-foot lateral. I think some of the wells, we're talking about drilling basically 300- to 400-foot a day. So if we plan for 500 feet,and we get out there at the log and everything is [indiscernible] and the log's still looking good and we're in good solid oil. Might we drill another 24 hours and keep going, yes, you'll see that happen sometime. The incremental cost of 500-foot screen and another day of drilling almost nothing to potentially double the EUR potential of the well by doubling the horizontal.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

And then kind of from the line standpoint here -- I guess, the bigger issue then is water encroachment as opposed to gas coning?

John Daniel Schiller

Yes, so far in horizontal, I mean, we had gas. We don't ever really see much gas coning as much as we had a few wells recently that we completed near the top of structures and we're having to blow down gas caps. I wouldn't necessarily call that gas coning, the oil's going to come at us. But yes -- and water, that's some of the stuff we're doing. One of the things we have right now, Andrew, is on the 2 wells we drilled today, we have the rigs and on top them, drilling the third well. So we haven't been able to get any production wells and then get some sense of where all the oil flow is coming from, et cetera. I think you'll see us do that when we get this next well completed. We're actually going to slide the rig on the side just so we can answer some of the questions you're thinking about with regards to the first couple of wells, where is all our production coming from? We know we have low delta p so are we getting flow throughout the lateral, are we getting most of the flow in the first 200 feet of the lateral, what's contributing. And once we get that, that will go a long way towards helping us understand how to do some of the new -- more design work.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

I guess lastly, do you -- as you look at this, I imagine -- do you see a lot of wells in the historical database? How big a fault can you cross? And is kind of, fault and reservoir, are they an issue in terms of limiting your lateral lanes? And do you have a limit at this point in terms of sand [ph] controller that go clean out?

John Daniel Schiller

We've looked at that. I would tell you that South Tim 54, Exxon kind of started there and that was where they did a lot of their experimentation. And several wells there, they tried to jump faults. It didn't work very well. Those are some of the operational disasters. And I mean, where they went from that gravel pack of set of 1x [ph] concentric packs inside the gravel packs and those failed. So I think right now, when we look at the historical data, you're not going to see us attempt to cross faults and that's one of the things we talked about, limiting the length of horizontal. We see out there the cross fault, that maybe all we can get is 500 feet without worrying about getting into the next fault. So I think early on, that's how we'll play the game based on what we've seen historical.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

And I guess last one, as you look at the reservoir modeling and what -- do you have to -- you foresee having to do any more additional surveillance work, I guess, to track the performance of that and see if you've got any unswept packs or unswept areas in the formation? Or you think permeability's high enough that you're not going to worry about, I guess, drainage issues too far from the wellbore?

John Daniel Schiller

That's why when you sit back and look at West Delta, those reservoirs the series of F30, 35, 40, and 45 sands range in size from 2,000 to 4,000 acres, had recoveries from maybe as low as 30 million barrels to as high as 65 million barrels already recovered per reservoir. So those are ones that we're looking to do simulation because you got a lot of data, a big area, and a lot of potential that you bypass some oil there. As a matter of fact, if you remember, we drilled the 4 vertical wells before we drilled any horizontal wells and that's one of the things we saw there. Different oil water context on different size of the fields, clearly areas that weren't being swept as well as other areas. We've seen evidence of that also in Main Pass 61 and we continue to model some of that, Don Tomas, what we saw there. Those wells all continue to tell us that mother nature is not necessarily getting everything out of the ground, so we've got to go help.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Could you give us a prediction on the score on Saturday?

John Daniel Schiller

Let me put it this way, I drill wells for a living, so I'm very superstitious but I'm doing everything exactly the same way I've done it for the last 2 road wins [ph].

Operator

And our next question comes from Adam Duarte of Omega.

Adam Duarte

On Davy Jones, I know for a while that the permeability of the well was still a question mark given what you had in the logs. As you've moved toward the flow test and finished the completion process there, have you seen anything that speaks to the permeability of the well and has that, I guess, changed your view of either the rock quality or the potential flow rate of the well with the flow test coming up so soon?

John Daniel Schiller

Adam, you know, across-the-board, we've always talked about the what-ifs on this thing. And, I think, the one thing I've always said is that natural fractures trump any conversation we're going to have about the matrix permeability of the lot. And when you look at the things we've seen from how daylight plugs were forming across the open perfs indicating permeability to the well kicking us, us being able to kill the well by pumping in mud. All of those things are indicative of permeability that's better than what we know the matrix block has or expect the matrix blocks to have. So it certainly acts like a well that has some fractures in it. I'm more optimistic today than I have been at any point in time in terms of potentially very attractive flow rates and God willing and everything working right, we're going to know an answer here pretty shortly now.

Operator

[Operator Instructions] Our next question comes from Joe Magner of Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

I'm not sure if I missed it or not. Just curious if you've provided any sort of pre-drill reserve expectations for either Pendragon or Merlin.

John Daniel Schiller

We didn't, we said one was 3x as big as the other though. I will tell you, Joe, that the numbers are all double-digit million barrels for those things and Pendragon actually gets the triple. I guess the key thing here is a lot of potential targets and a feel of where you got pretty good sense of the sands are there. I would tell you that on a list basis, the initial well, highly risked, you would expect to find some pay in one of those 10 horizons. If you take the most likely outcome and you start filling up those sands, you can get the 40, 45 million barrels of oil in there. And then it goes from there to Pendragon where you got 21 potential sands. So I wouldn't go booking all those Day 1. It's all going to be about where we see the sand and how many are full [ph] of oil. But Pendragon is about 1/3 the size of Merlin and we'll drill Pendragon first.

Joseph Patrick Magner - Macquarie Research

And it's not, I guess it's not clear from the map that's in the deck, but how quickly do you think, if you do have a discovery on one of these how quickly could you get that completed and, tied in, what's the sort of expected timeline?

John Daniel Schiller

No, that will be fairly quick. All we got to do is we're actually going to take a caseline we already have, put it on the well and will be out like a flow line. So production is, 3, 4 months?

David West Griffin

4 months.

John Daniel Schiller

4 months, we should have our first production. We're going to model the first well coming online right at the end of this fiscal year from a prospective win. And then the other thing to keep in mind, Joe, is because the targets range over large intervals, I think we'll see that -- you'll probably get news flow there incrementally as we go through the reservoirs. It's not going to be like you're waiting and 1 log run is going to tell us everything. We may get into some shallow oil and talk about it and then some oil down below 12,000 et cetera, all the way to 16,000 feet.

Joseph Patrick Magner - Macquarie Research

And then I'd imagine there's going to be some sort of a staged completion as you work your -- depending on where hydrocarbons are found as you work your way back up.

John Daniel Schiller

Let's go [indiscernible] and we'll figure it out. We're always going to look traditionally, we'd like to come from the bottom up, but we're also going to -- might very well take a big oil sand versus a gas sand at the bottom and come back and develop that later.

Joseph Patrick Magner - Macquarie Research

And then just on -- maybe you could give us an update on the -- I guess current state of the market in the Gulf of Mexico with respect to acquisition opportunities. And then also, I think you've voiced some interest recently in terms of considering some international opportunities, just maybe an update on the latest thoughts on both fronts there.

John Daniel Schiller

There continues to be a decent amount of deal flow. A lot of it is more gas-oriented and probably not stuff we're that interested in. I think at least with regards to the Gulf of Mexico, if we do something on the gas front, it's going to have to be around something strategically that we own interest in or offsets something we own interest in and we know the play really well. There are some deeper water packages coming out. As we've talked about where we already have field on production and we can go out there and operate on a platform in the same way we operate on the shelf and we're not talking about the long lead times associated with exploring in the Deepwater, I think you'll see us look at those opportunities. There's not a huge amount of those coming right now. And on the international front, yes, we're talking about we're looking there. I don't think that's a near-term build. I think anything of size there is 12 to 18 months out in the horizon.

Operator

Our next question comes from Dan Tecksey [ph] of Global Credit Advisers.

Unknown Analyst

A couple of questions for you. The first one, I don't know if I mentioned this, but in your oil break out for this quarter, how much of that was NGLs? And then can you provide an average price that you realized on that.

John Daniel Schiller

Yes we did, actually. It was in my commentary, it's 8% NGLs out of the oil. For the 92% of our oil volumes, we realized $107 a barrel. For the 8% NGL, we got $35 a barrel. You can see what a great job our friends at liquids-rich gas have done for us on NGLs. [indiscernible] where we got about 60% of the barrel.

Unknown Analyst

Okay, and then in terms of your direct LOE, obviously this was impacted by Hurricane Isaac, going forward in the next couple of quarters, can I expect this to go back to the historical range of the mid-to upper 13s and then, going forward, as you focus on more horizontal drilling, how do you expect that's going to change?

John Daniel Schiller

Yes, I think obviously when you have a hurricane, you have to spend money out there to go repair things, and that all jumps in the LOE. It sort of -- it increases the direct cost, offset by the fact that you're producing less, so your barrel oil equivalent jumps through the roof. I do think you'll see us go back to historical numbers. We need to see, as we bring on the horizontal wells, if we start getting a lot of water production associated, there may be a little bit of creep on your LOE per barrel, but nothing significantly. So I think if we're in that $13 to $15 sort of range, you're going to be in the right model area for drilling.

Unknown Analyst

And then last question on Davy Jones, when you're saying you're nippling down the BOP, can I assume that you guys have run the same pressure test on the seal that failed the first time around?

John Daniel Schiller

Yes. All our seals are tested, the packs are set, 2-week time off on the tubing to hit. And so you nipple down, which is oilfield talk for taking it apart and take your BOPs off the top of the wellhead. And the next thing we'll do is nipple off, or attach the tree, and then we'll be in a position to start hooking up to do the flow.

Operator

And our next question comes from Joan Lappin of Gramercy Capital.

Joan E. Lappin - Gramercy Capital Management Corp.

Hard to believe it's a year later on the Davy 1. Can you tell us once you complete these last few tasks, which sounds like maybe it's 48 hours or less, how long does this -- what is the -- can you walk us through the flow test? What's going to go on, how long it's going to take until you see what's going on? How you -- I mean do you still have to clean out junk that's coming up the hole from all this stuff that's been going on in there. How long does that take until you can actually hook up to the pipeline and start sending stuff off? And then, John, if you could get into -- once this thing is hopefully flowing, what are the ramifications and how will that affect the timetable for Davy #2?

John Daniel Schiller

I'll take the last part of your first question first. After we've finished the flow test, we're about 20 days to commercial production to make our permanent hook ups and be flowing into the facilities. The flow test itself, Joan, a lot of it -- it's an old phrase, but a lot of it's going to be how the well talk to us. If the well's doing all the right things, we could be 10 days of flow and then have everything we need. If some of the other things we've talked about, if it's harder to clean up and things like that, it could take a little bit longer. I don't think, whether it's short or long, it's necessarily going to be indicative of how good the well is. I've done a lot of well tests in my life, there's a lot of hiccups that happen along the way and this is hard. You literally go out there and what you basically want is we want to get this well coming at us good. We want to get it on loaded. We want to get all the fluid out of the wellbore. And we want the reservoir to be talking to us and telling us how good it is. And then from there, we can start deciding how long do we flow it before we do build ups, how long of buildups do we want, et cetera. And it's just hard to give you a firm timetable but I will tell you that I fully expect us to start that process next week. I don't know where got 48 hours from. With regards to your last question, I think it was about what does it mean for Davy Jones #2. I don't really think anything we're doing here in terms of flow rates or what we see is going to have much impact on when we do Davy Jones #2 as much as equipment that's being built and some of the things that are getting done there and some of those deliveries have been pushed back a little bit. So I think it's -- I don't see us moving from here to Davy Jones #2 is what I'm trying to say.

Joan E. Lappin - Gramercy Capital Management Corp.

What do you mean equipment push back? Is that because every Jim Bob asks for white papers on everything? Or is that because there's some problem with delivery or...

John Daniel Schiller

No, it's just we have things like sub-surface safety valves and the perforating guns and packers and couplings for the tubing and some of those delivery dates have slid. As you might imagine, I mean we got everybody's attention early when the deepwater wasn't doing anything. Now the deepwater well takes off again. You got to get in line behind manufacturing some of the other stuff. So it's just some delivery dates from the vendors have slid. It's not about design process or anything like that. It's just actual manufacturing delivery dates sliding.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay, can you talk about Crete? I mean you have it on your, whatever slide this is, I don't know, Slide 8...

John Daniel Schiller

We've started the permitting process on Crete. Expect to spud it sometime hopefully in the first quarter next calendar year. So I think...

John Daniel Schiller

How deep is that going to go?

John Daniel Schiller

About 18,000-foot TVD.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay, so everything is very standard equipment off-the-shelf.

John Daniel Schiller

Exactly.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay, so as you look at your participation in the shallow water ultra-deep now, do you see in the future more land-based stuff or -- I mean I can't imagine we're going to have another well that costs as much as Davy did because we're never going to have so small a hole again. But give us sort of an overview as to where the program overall is, and your enthusiasm for it.

John Daniel Schiller

Well, you're probably asking the wrong guy. The other guy has a lot better vision and knows what he wants to do a little bit more than I do. But I will tell you that if I sit back and look at things, successful test of Davy Jones #1 gets you excited about Davy Jones #2, obviously. Well, feeds, we already feel pretty good about because we have better log in [ph] tools there. I think you have to see what happens at the Chevron well. You have to see what happens at the well we're drilling onshore. And as you get all that data, then yes, it starts making decisions for you with regards to what are the right reservoirs to chase and what are the right structures to chase them off.

Joan E. Lappin - Gramercy Capital Management Corp.

And finally, could you give us some amplifying commentary on Ship Shoal 188 and what's going on there? It's kind of hard for us as observers from way outside to get a sense of what's going on.

John Daniel Schiller

Yes. So at Blackbeard West we've got -- we originally were going to drill at 25 5. We backed up to 24 5 because the government wanted us to run what's called a tieback line or a tieback to drill with. We ended up running the tieback anyway, which is an expensive move because we're rubbing holes in our casing shallow. And so since...

Joan E. Lappin - Gramercy Capital Management Corp.

Wait a minute, you're over my pay grade here. Can you explain why the government wanted that, why do you did it anyway and the last thing you said.

John Daniel Schiller

Yes, but we're going to bore everybody, Joan. But the reality is, the way we design wells is we try to get by with the least costly casing we can shallow. If we have success, we put the well on production. Then we run beefed-up casing all the way to surface, and that's called a production tieback. Sometimes you get nervous about your pressure at that hole and you run a drilling tieback but it's not cheap to run that one. You don't know if you're going to have success or not yet. So the government wanted us to run it if we were going to drill below 24 5. We said, fine, we won't drill below 24 5. Then as we were drilling ahead, as you spend all this time rotating the pipe, we started seeing with one of our casing -- our casing up hole was starting to get thinner and we had to make the decision to run the tieback anyway. So now that we have it in there, we're going to drill another 1,000 feet ahead to 25 5. Once we're at TD, all we really have right now is some electric logs which give us some data but not all the data we need to evaluate. So then we'll run a full suite of logs. Once we get cores and pressures and the DSPs [ph] on the side [indiscernible].

Thank you, everybody, we're going to get out of here and go on to the next meeting. Thanks.

Operator

Thank you, ladies and gentlemen. Thank you for participating in today's conference. This concludes today's program. You may all disconnect. Everyone, have a great day.

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Source: Energy XXI (Bermuda) Limited Management Discusses Q1 2013 Results - Earnings Call Transcript
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