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Energy XXI (Bermuda) Limited (EXXI)

Q2 2013 Earnings Call

January 31, 2013 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

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

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

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

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

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Operator

Ladies and gentlemen, good afternoon. At this time, I'd like to welcome everyone to the Energy XXI Fiscal Second Quarter 2013 Earnings Conference Call. [Operator Instructions] Today's conference call is being recorded.

And I'd now I would like to turn the call over to Stewart Lawrence, Vice President of Investor Relations. Please go ahead, sir.

Stewart Lawrence

Thanks, John. Welcome to the call everybody. Presenting today, we have 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 yesterday and in 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.

I'll turn it over now to John.

John Daniel Schiller

Thanks, Stewart. Welcome, everyone. We released our second quarter financials yesterday, including a lot of information about our ongoing operations, as well as an acquisition we just finalized in South Louisiana. Our oil production continues to deliver over 90% of our revenues and we continue to focus on all the opportunities highlighted by our ongoing horizontal program that is adding both production and new reserves.

The program is looking very promising. There will be some ups and down along the way and we will stub our toe from time to time, but taken as a whole, the program remains extremely encouraging.

In addition to the Velman [ph] activity, our exploration prospect, Pendragon, is drilling ahead at Vermillion. In total, we have 5 operated rigs currently drilling with 2 more preparing to scrub with onshore barge wells. So we're excited about the remainder of our fiscal year.

And before I get into those details, let's have West go over some of the financial information. West?

David West Griffin

Thanks, John. Let's review the quarter starting with volumes. We averaged 44,600 barrels a day for the quarter. That compares to 42,700 barrels a day in the second quarter of fiscal 2012.

As we stated in today's release, current production is about 47,000 barrels a day with capacity of almost 52,000 barrels a day. That means we currently have over 9% of our production capacity offline for various reasons and actually, averaged more than 10% offline in the December quarter.

Since mid-2011, when we began operating the Exxon Mobil properties acquired in December 2010, it has become apparent that the older infrastructure has resulted in higher downtime. With our drilling success, we have been moving more fluids through an aging infrastructure, which led to a higher-than-expected downtime associated with compressors and pipelines in those fields. When they go down, they're more likely need to be replaced rather than repaired. But these are growing pains, not a long-term issue. Gradually, the infrastructure is being updated and we're confident that we can reduce downtimes to more normal level. Until then however, we are adjusting expectations to assume some higher downtime.

Using those adjusted expectations, oil production should average between 30,000 and 32,000 barrels a day this quarter and between 36,000 and 38,000 barrels a day in the fourth quarter. With today's margins, that would trigger the best EBITDA in the company's history. Pretty much regardless of the success, we have been increasing natural gas volumes.

The impact of our second half oil-focused drilling program shows up in the exit rates, which should approach 40,000 barrels a day of oil, 25% higher than the prior year exit rate. Going back to the December quarter's results, premium Gulf of Mexico pricing on our HLS group continued to generate solid revenues on a BOE basis. Our pre-hedged oil price averaged more than $107 per barrel last quarter. NGLs were 6% of reported oil volumes and combined with natural gas prices, our realized price per barrel equivalent averaged $78.15. While our pre-hedged oil price was $107 last quarter, we are off to a great March quarter with pre-hedged oil prices for the month of January averaging almost $115 per barrel.

Turning to our operating expenses, you will see that for the quarter, LOE was down over $3 a barrel to $20.95 driven by a reduction in direct LOE expense. Other expenses were generally in line, so EBITDA was a healthy $48.47 per barrel.

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

John Daniel Schiller

Thanks, West. Let's start by discussing our horizontal program ongoing at West Delta. We've now drilled 3 successful horizontal wells there, Big Sky, Weimer and Hyden.

On Slide 7, we show you a comparison of those 3 wells against the average horizontal wells type curve drilled by Exxon in the field during the '90s. What you see are the declines we all expected to see initially and the way the well, so far, is parallel to decline occurs on those historical wells. What's important to point out is that we brought our wells online at higher rates initially. Combined with strong oil prices, that means payout on these wells is going to be anywhere from 4 to 7 months. Fourth [indiscernible] we have our third-party engineers look at the data and they estimated reserve range between 1.2 million and 2 million barrels per well.

Currently drilling 4 wells with horizontal potential, one at West Delta and Grand Isle, South Tim 54 and Main Pass, all of which will contribute to our second half growth rate.

Slide 8 shows you the expected impact of horizontal program on future oil production. As you can see, this has proven to be a successful program today and we'll continue to update as soon as we get more results.

As I mentioned earlier, not everything is going smoothly as the 3 wells I just showed you. The DrO got hung up in salt and we encountered different water levels once we got out of the salt, so we temporarily abandoned it. I'm convinced we may have to go back and sidetrack at that wellbore at a later date and get into our target sand. But for the quarter, it certainly was a disappointment in terms of volumes we were counting on. Even more frustrating was the Sparkplug well at South Tim 54. After several attempts to drill to the H-3 sand, we decided to take a completion in the H-1 sand.

After running the production line and we are pulling out of hole and had to stop and trust our BOPs. One of the roughnecks on the in-still rig managed to close the shear rims, seal in the drill pipe and sending the liner hanging toward the bottom were it jammed into the liner top. We've ended up having to junk that well and cost another couple of thousand barrels a day expected production, not to mention CapEx with no results.

Then we had the Pine Cake well, a little bit different scenario there, both successful wells. They were completed in what we believe to be small gas caps, but for various reasons, both wells produced mostly gas for the quarter. As part of our production mix turned a bit gassier for the quarter. But now both wells are doing what we expected them to do from the start and that is oil caps starting to come out nicely. These should end up being very good wells for us making both our reserves and value expectation. This is going to happen as we drill these added shots in these large old reservoirs. You're going to have secondary gas caps and from time to time, we'll make the completion and have to blow down that gas before we get the oil to us.

Over at Main Pass, the Monte Carlo well has extended the size of the reservoir at Pod A. The well capped in the sands that are outside of the mapped amplitude but in pressure communication was the main reservoir. So we'll put new reserves there. Currently, the well's producing about 250 barrels of oil a day and the extension of that reservoir gives us a new data point to begin chasing additional tie-in at J-6 sand to define the extent of the oil pool.

Currently, we're drilling the Camacho well to look to do the same thing on Pod B to the south, where we'll be tagging outside of the amplitude there with our first wellbore there.

At South Pass 49, we have a regulatory completion program utilized on a hydraulic work-over unit, targeting our D-65 sand, which we showed you during Investor Day. The first well we reentered was frac packed and lucid production from 2 men a day to 17 men a day and we're currently working on our second hole [ph] there right now as soon as we pack around the hole there we'll be making our completion. There's a lot of good work getting done which is going to pay dividends as we get more and more data to work with.

Slide 9 provides our inventory update and more granular look at our 2013 drilling program. We show the wells here by field including 9 more horizontal locations and 4 key exploration wells being drilled in the second half of this year.

Currently, we're drilling Maroon, Iceman, Gelato, Camacho and of course, Pendragon, in addition to the non-operated wells. At Pendragon, we've reached case in point 11,577 feet measured depth. Once we get that pipe set, get back to drilling and we'll start looking for our targeted intervals there.

Also on Slide 9 is the DuPlantis well on the bicarbon field that we've -- where we recently purchased McMoRan's interest and gained the operatorship. That deal just closed a couple of weeks ago and is effective January 1, 2013. $80 million included McMoRan's 37.5% of working interest in the Landers wells and the Peterson wells, which took our working interest to 56.25% and added about 2,000 barrels a day equivalent to our production.

So current production net to Energy XXI from those 2 wells a day is approximately 2,900 barrels of oil equivalent. This strategic acquisition allows us to take over as operator and proceed with development drilling, as well as target some additional sands for exploratory drilling. That leads to the capital program.

Excluding acquisitions, we now expect to spend $730 million to $760 million this fiscal year. That has allowed us to add 2 onshore rigs to drill the DuPlantis and Pintail prospects, which hold the potential to add significant reserves and production. In addition, the higher capital allows us to extend a couple of rig lines into the next fiscal year since the market has continued to get tighter and we want to ensure that our program doesn't stall, while we're waiting on rigs.

So with that operator, let's turn it over for some questions.

Question-and-Answer Session

Operator

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

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Gentlemen, last quarter, I asked you guys and you alluded to it, that your internal reservoirs in the areas are looking at EURs for the horizontal program of 1.2 million to 2 million. You laid out in the slides how they're all tracking in line with that at West Delta 73. When -- I guess when you look at the program, one, what do you think will give you credit for in June reserve bookings in terms of PDP and PUDs? And how has this changed how you think about what drillbit reserve growth can look like over the next couple of years?

John Daniel Schiller

Yes, David. First off, the EUR 1.2 million to EUR 2 million, those are quoting reserves that we already have another sort of blessing on so we know we're getting those as PDP. And I would tell you that I think we feel very good at West Delta now with everything we're seeing that we probably have as many as 40 locations in the different sands there. You got about 6 different sands with those big, gradual structures that you can put a lot of wells into. Remember we've got the reservoir simulation from the Schlumberger on FW5 that supports 8 more wells and about 16 million barrels. I think -- I'd love to tell you what I think's going to happen, I think we will get a lot of PUDs in there. I think the reserves per PUD will go up. I will tell you that on some of these wells we're drilling right now, there are already PUDs on the books and sort of the 400,000, 500,000, 600,000 range, so we're doubling and tripling what's on the books where there are already PUDs. I think we just got to get a little closer and get a few more wells drilled to figure out just what it's going to look like long-term but obviously, it's very encouraging right now. And one other point to you David, so you know, when we're doing things, we're cutting off that production at 20 years to quote you reserves we got out of ground in 20 years. We [indiscernible] produce a lot longer than that, above economic limit.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Sure. And that -- could you give us any more color on how strategic Laphroaig is to you and what you might be looking there in terms of additional sands? Is it all gas pay that you're looking for? Are there other reasons why you looked at acquiring a larger interest in operatorship there?

John Daniel Schiller

Yes, I mean if you go back and remember the history of that field, we drilled the Laphroaig well first, brought it on at 40-man a day. Early on in there, we read we get some pressure buildup data that when we looked at it seemed to indicate we were tied in to a much larger reservoirs on the order of magnitude of 200 Bcf. So our guys set about mapping it and getting what they could out of size. We just think the structure is a little bit bigger and has a lot of running room on it so then we drilled the second well, which actually got up-dipped to the first well in MA-11 and found the MA-10 and Seven sands full. So the second one has actually been producing from a second reservoir. One of the things we'll do there is get the rate back up to 40-man, it was down to 32, and we're also trying to get us some build up data in there to help us understand how big that reservoir is. So when you look at all that together, you guys have been following us a long time. Know that we've always felt like there's some potential for 1/2 of tcf of gas there. Condensate runs 15 to 20 barrels a million. So if we're right, when we drill this next well, we're going to have a nice development program there with very high Btu-quality gas with condensate and I think economically very attractive.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Yes, if I could just lob in one more quick one, as you look at some of the downtime you've experienced over the course of last year, certainly as you go into some of these aged Exxon fields, when do you guys see sort of like the light at the end of the tunnel where we don't have to see as much of a gap between productive capacity and sales and really see minimized infrastructure downtime start supporting your growth program?

John Daniel Schiller

Yes, I mean as we talked about downtime for long periods of time that the hurricanes do a little damage that we didn't really realize at the time, that's why pipelines start leaking. There are a lot of things involved there. I mean, the difference over the past years that we did have a hurricane come through there that wasn't a bad one, but we're having increasing downtime. I see also David, the part I can't make go away for you is we're going to drill some 3,000 and 4,000-barrel a day wells like we had at Onyx and if they go up production quick, we're going to probably have a trouble with the forecast and vice versa if we don't get one of those wells online and that's we're really been fighting. We don't talk about as much in there but just the timeline, when you think we lost 3 weeks of production from the hurricane, we really lost 4 weeks of activity from our rig. So that slides everything back a month in terms of when you get it on production. And with a couple of other rigs, we lost 2 weeks during January because of how bad -- one after another got blown in 3 weeks [indiscernible] went through a 2-week period from right before Christmas to right after New Year's, where a couple of our rigs got no work done. One was waiting on our frac that couldn't work in the wave and the other one was trying to get oil-based mud pulled onto it. So those type of things start backtracking on you when you can bring wells on and it's just a nature of the beast. So obviously, what you saw West do today is we're going to start trying to take as a conservative approach as we're comfortable with and give you guys some good base guidance. And hopefully, when some of the good wells go the right way, we'll surprise you to the upside.

Operator

Our next question comes from Michael Glick of Johnson Rice.

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

Just a question on the Ultra Deep. Looking at the McMoRan SCX deal filings, it's pretty clear that McMoRan believes that Lineham Creek is a significant discovery in the Yagler [ph] formation. Just a question, do you guys kind of share that view and what would you need to see to be able to book reserves out there?

John Daniel Schiller

Yes. I think that we're learning a whole lot about the play. I think seeing the Yagler [ph] sands up there was -- is a very nice long jump particularly when you're chasing the Wilcox. I think we got to continue to get core data. We're currently coring with that well right now down deeper. And so hopefully, we get all that data together and we continue to unravel the keys to understanding the play. But yes, there's a lot of encouragement. We sit back and look, every structure we penetrated below the salt has held gas. So Jim Bob's original pieces are holding very steady, but there's a lot of gas down there that's getting trapped.

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

And then shifting to the horizontals, is there anything you guys are doing on the choke management side or looking at doing that might translate to maybe just slightly lower IPs but higher EURs over time?

John Daniel Schiller

We missed the first part, is there anything we're doing what?

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

On like the choke management side? Maybe not pulling your wells as hard?

John Daniel Schiller

Yes, I mean, we look at it every which way. We've brought the first one on pretty hard, Big Sky, starting trapping the water early, we got nervous that we had a problem behind pipe then went out there and it turns out all the water's coming from the very end of what we call the toe of the horizontal, which is perfect, that's fine. That's why we dipped down closer to the water contact and so we're doing a -- and we're still draining at 800 feet of oil out of that 1,000 feet. So we feel very good that, that's going to be a good, long-term well. The second one, we didn't get near as good a lateral, but still we got 1.2 million booked to it and it's producing nice 400 or 500 barrels a day as you see on the curve. Hyden, we actually did baby in, we brought it on at 1,000 and let it just sit there. What happened is that it kept cleaning it up and getting better and getting a little gas and the tubing pressure kept rising so we ended up opening it up to the current 1,600, 1,700 barrels a day that it's making, and it's producing water-free now for months. So each one is a little bit different. We kind of showed you what we think. We think the decline curve doesn't really change whether you baby them or whether you bring them on. It is what it is in each one of the reservoirs. Now we may treat them differently depending on where we think the water contact in each one and some will drill closer than the others. But you really just -- when you talk about pouring one of these hard, David, I mean, Mike, you're talking difference between 5 pounds drawdown and 10 pounds drawdowns. I mean the drawdowns are almost unmeasurable on these things.

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

And then just on the production mix, you guys NGL percentage has declined pretty significantly since the calendar first quarter '12, how should we think about NGLs going forward?

John Daniel Schiller

I think the NGLs where we are right now, if memory serves me well, are where you should be seeing things. I think there were some adjustments a while back where we had to do some property adjustment to jump NGLs up for a while for catching up for when we first did the Exxon deal and we didn't realize all the NGLs we were making. But you're going to see another jump now with the increase at the value column across McMoRan and that well's pretty good NGL. So we will creep up some there.

David West Griffin

It's still a rate of about 6% to 8% is probably still the right area.

Operator

Our next question comes from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

You noted that the oil cut fell in fiscal Q2 to 66% from 70% the quarter before. I was just hoping you could map this out for the remaining two quarters' outlooks?

John Daniel Schiller

Yes. I think you'll see us stay easily above 65% and prior back closer to 70%, as I mentioned. Now we've brought on a good well at the South Pass 49 field in the D-65 sands. So obviously that's a decent amount of gas but really the difference versus what we had planned was the 2 oil wells were started as gas wells. Obviously, bringing on the McMoRan production out at Bayou Carlin is going to trigger just a little more back to gas. But I think somewhere between 65% and 70% is a pretty good model, shouldn't go much lower than 65%

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And just on the plug for the guidance for the next quarter that West just gave into the model here, it looks like you're ultimately going to come out probably about 25% lower than the original guidance you gave at the time of your Analyst Day. And I just wanted to make sure I completely understand the drivers of this characterized as 50% of the Delta explained by drilling delays, 10% hurricane. However you'd look at it.

John Daniel Schiller

Yes, I mean, I think the biggest part is well performance. If you go back to right in front of the Investor Day when we showed everything, we had the Costello well making 24 million a day and another 3,000 barrels of condensate. So it was making 6,000 barrels a day net to the company on its own and we had the 3 wells at Onyx making 9,000 barrels a day, 8,000 to the company net. So that 14,000 barrels a day pretty much disappeared over the next 2 months, that's where a huge bit of the performance is. Then you take out Sparkplug and you take out DrO from the volumes we've had some surprises here and there. Obviously, South Pass 49 that well came in better than we had modeled. The Winters well, the original gas well we drilled over at Grand Isle continued to outperform. But that's kind of where we're at right now. The outperformance has been from the gas wells and the decline performance has been from the oil wells, it's not what we want. So that's the large part of it and the biggest part of volumes after that was making the decision not to drill Golden Bear and Wombat, the 2 other higher-rate 40-million-plus a day gas completion and replacing that with a drilling at Vermillion for the Exxon exploration. Those are the big chunks of it right there.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it. If I could sneak one more in, just the economics of these horizontal wells are certainly compelling. The rates returning you get there are obviously phenomenal. I was hoping if you could talk about the -- just the dry hole risk of the horizontals and if it is a riskier program than the typical vertical drilling program?

John Daniel Schiller

Yes, that's a great question and one we've been talking a lot about. Over at West Delta itself, I would tell you, very low risk of dry holes just because of the gradual four-way structures you have there. We know very good Information about the sand, it's very continuous so -- and in today's technology world you just can't miss those. So we should have more dry holes there. Maybe we have -- the sidetrack issue, we have some mechanical risk every once in a while. So let's say 90% is what we run, but it'll be very high. On the other one, one of the things that Ben and I have been talking about this week is, perhaps, what we need to do is rather than trying and coming to these well bores at 70% when we drilled our pilot, is drill as quick a straight hole as we can get, so even if it's an S-shape hole and target where we want that hill, where we want to make the penetration point at and make sure we have pay there and we're not up into these faults or into the salt, which is what we're trying to do on these other fields. And once we know that point, then we can come back up a little higher than we've been and sidetrack but we'll know we'll be sidetracking to where we have sand. And so I think, in that situation where we don't have the general pull for that price, say, 75% success, somewhere in there. Yes, so call that 75% success rate.

Operator

Our next question comes from Duane Grubert with Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

John, McMoRan who's not the operator nor you, are involved in the -- let me rephrase that, the Lineham Creek well that Chevron is operating apparently is going to have some cores and the mini frac work and the frac work that's going on at Davy Jones might be informed by that core work, can you tell me what kind of information might you get and what is your thinking about what additive information could help the frac work for Davy Jones that might come from Lineham Creek?

John Daniel Schiller

Yes, I think the key things there are, if I had Adam Olszewski on the phone with me, what he would tell you is, we're convinced that the Wilcox is naturally fractured. When you look at all the rock we've gotten out of the ground although we've never had the Wilcox sand itself out of the ground on those wells, what we did around it and indicates to us we have natural fracture. What we don't know for sure is what's in those fractures and what we need to do to get them open. If we need to do anything, we might not need to do anything depending on where the wells are located. So yes, once we -- if we can get us some cores from both of these other 2 wells that we're drilling, understand a little bit better about what's been going on down there, over 40 million or 50 million years, then I think we got a good chance at making things work across the play.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

And similarly, going back to the Lineham Creek well, a lot has been done prior to 12-31 and when McMoRan commented on whether it might be able to book reserves for that well as of the end of 2012, they said they were working on it data wise. You guys don't report reserves until mid-year, do you have confidence that there's enough data there that there will be some reserve bookings for what you have already seen at Lineham Creek?

John Daniel Schiller

I think, maybe. And we just got to say is, it's getting more data down below will probably help the reserve auditors with what we are seeing up above. For us because we only have 9%, it's not really that big a number of impact either way for our first booking.

Operator

Our next question comes from Steve Berman with Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

Can you elaborate a little bit more on the production guidance? Just I'm pretty sure I heard you say the guidance for West Gate was just oil so and you talked a little bit about the gas. I might have missed that, so did I hear you say 65% to 70% oil mix for the next couple of quarters, no less than 65% up to 70%? Just want to make sure I heard that right.

John Daniel Schiller

You heard that right. 30 to 32 barrels of oil for the next quarter and trying to get 36 to 38 per quarter after that.

Stephen F. Berman - Canaccord Genuity, Research Division

And that assumes similar kind of downtimes to what we've been seeing in terms of percent or is it getting better over the next couple of quarters? I know you said 10% average in the December quarter. What are you assuming for downtime in the next couple of quarters?

David West Griffin

About 10%.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. Timeline on Pendragon, when do you think that will be done and when will we know what you got there?

John Daniel Schiller

45 days, we should be [indiscernible].

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. And with success, how long it will take to bring that onto production?

John Daniel Schiller

[indiscernible] rigs to completion?

David West Griffin

It's between 3 and 6 months to get the permit, get the case on installed full line laid.

John Daniel Schiller

Remember this is the one -- once we have the completion there, we'll tie it back to the existing platform on the other side of the dome so it's high 5, 6 months, low side 3 months to production.

Stephen F. Berman - Canaccord Genuity, Research Division

And on the horizontals, you've used an, I believe 800,000 BOE EUR in some of your recent presentations, was that the kind of a company average you were thinking or was that just West Delta and with the success of the first 3? West Delta horizontals and the 1.2 million to 2 million BOE estimate, is that 800 number obsolete and do you see that going up?

John Daniel Schiller

Yes, that 800 is my conservative West Delta engineer on the regional work. So throw that number out the door.

Operator

Our next question comes from Richard Tullis of Capital One Southcoast.

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

John, I know West outlined the production outlook going through year end, fiscal year end. What about looking out a little further? How do you see oil production growth or just total production growth going into fiscal year '14, fiscal year '15? What sort of adds do you think you're looking at?

David West Griffin

We're just looking at our long-term strat plan and so we have looking at fiscal year '14 ways we're thinking about it is we look for an exit rate in this fiscal year about 40,000 or so barrels a day. And fiscal year '14, the name of the game is trying to hold it flat at that sort of level on average for fiscal year '14. And in fiscal year '15, you got another 10% or so growth beyond that.

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

Okay and that's on the oil side. How do you see the gas holding up, kind of flattish concerning Laphroaig?

John Daniel Schiller

Yes. I mean, if we have success rolling, the plan is where obviously gas is going to be up pretty quickly, big great wells with a huge percentage going to us.

David West Griffin

But you have an aggregate oil going up so the mix between oil and gas aren't going to change that significantly.

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

Okay. I apologize if you mentioned this, what was the cost of that Hyden well?

John Daniel Schiller

Cost of the Hyden well?

David West Griffin

Yes, $11 million, $12 million.

John Daniel Schiller

$12 million

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

Okay. And what do you think the incremental cost was versus the vertical?

John Daniel Schiller

About 2, somewhere in there.

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

Okay. Getting back to the ultra-deep, John. Going forward, I mean how many wells and how much capital would you like to see dedicated on a net basis to that program going forward?

John Daniel Schiller

I'll make a couple of comments and then I'll finish with saying something else about the ultra-deep. But I think going forward, I don't expect us to drill a well in open water with a Rowan type rig the rest of this year. I think you can see the effort move onshore like it is right now, if we drill in open water, it would be probably near shore with a barge rig, also something like England, so I think that by itself starts driving down your costs. I think I'm comfortable with about $100 million a year going to that effort. And I'll also say that I think the biggest thing that some of you picked up on once the SCX deal closes with McMoRan and Planes, we've become the materiality test for what's important with regards to the ultra-deep. So I think that you're going to see the information flow get a lot less. We're not going to sit here blow-by-blow in everything we do. If we have something material, we're going to tell you about it, other than that, you probably can ask all you want but it won't be near the kind of talk that's going on once we move into the new world.

Operator

Our next question comes from Adam Michael with Miller Tabak.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Wanting to go back to the Vermillion block and revisit the Pendragon well a little bit. Can you just briefly discuss kind of the targeted zones there and if I recall, I believe there are some production from the Vermillion block to the north and just maybe a little bit of that confidence level and what kind of probability we should assign to this thing?

John Daniel Schiller

Sure, Adam. A real quick history. So Exxon has the production on the north side of the dome. They found initial field in the 50 shallow sands, actually abandoned the field and gave up the lease, then came back in the '80s and then took the lease back again and drilled deep along the salt and found the deeper sand. In general, those are the target sands we're going for on the south side, not the shallow stuff, but the deeper stuff. The first well has 10 identified amplitudes in it. We're probably about 30 days behind mainly because of what I just mentioned to you, we set there for 2 weeks with the boats unable to get us mud. And we lost another 2 weeks moving out of the shallow gas sand, water sand trying to flow on the backside and get the primary treatment job. So you got to slide everything back about a month on that well but things are going good, we're going to be getting the slider on the hole over the weekend. And then from there, we are going to start drilling up at a pretty good pace and start looking for pay [indiscernible] for about 2,000 feet from the first amplitude.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Okay. And if this well is successful, what's the next well and can you talk about the structure size on the first couple of Vermillion prospects?

John Daniel Schiller

Yes, I mean, if we're successful on the first well, we have to let go of this rig. Rig market's pretty tight. We only have this rig for one but we've got another rig lined up, we would then go to the Pendragon and drill that one, which is -- I mean to Merlin, but remember Merlin has 21 amplitudes in it and it's the largest reserve block out there, we just like the geological trapping of Pendragon a little bit better. So we get those 2 wells on then I think you're talking a sizable 4 probably with capacity for 20,000 barrels a day fluid, maybe 30,000, total, including water and easily 50 million to 100 million a day of gas. We're a little far away from that right now just get one discovery and then we'll go to the second one.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

So If the success at Pendragon like make you more confident in the next well, which I believe you said was Merlin?

John Daniel Schiller

Yes, correct. As a matter of fact to the point that if we don't have success on Pendragon, the next prospect will be Guinevere. So we've got a follow-up that's depending on the success on what we see in the first well there, we go either way.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Okay. So I assume Pendragon would be a material event then you'd probably communicate any positive news to the market. You said 45 days to TD.

John Daniel Schiller

That's correct.

Operator

Our next question comes from Andrew Coleman of Raymond James.

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

I had a question on the capital plan of the 730 to 750. Can you break that down between facilities drilling to completion?

John Daniel Schiller

Andrew, West will get that for you real quick.

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

I guess the second question was then, you have about $120 million on the M&A side so far this year, I guess, how would you characterize the market for properties out there and do you think that there could be much more coming?

John Daniel Schiller

It's not as big as it was. It's -- with the Helix property was gone, there's some stuff floating around. There's been interesting enough -- a couple of deals put out and basically have bids rejected is not acceptable. Those tend to be on deals, let's say they're 50% of Gulfs [ph] so you got a lot of running room, since you get a disconnect there between what buyers are looking for and what sellers are willing to pay. So I think we'll continue to look. There's more options, we're always monitoring with regards to big oil fields and to potentially get into them. But as I've said all along, for us to do an acquisition it has to be has strategic, it has to be meaningful. Obviously, the deal Bayou Carlin was both of those, it gives us a lot of running room what we think is a very sizable discovery. And anything else we'll do will be along those lines where we know it fits into our operating mode and we can get some synergies and we can make what we're doing on our fields right now work on those fields.

David West Griffin

Yes, I'll go back and answer your question on the CapEx. Of the total, you've got a total of about $32 million for land and G&G. The total development is $416 million, $90 million on exploration, $80 million for the ultra-deep program and then you have the miscellaneous other.

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

Okay. And then thinking about the new guidance there for the next 2 quarters and your hedging profile, do you have much room given the strength of HLS here in the short term? Would there be any need to add to hedges there? As you look at the market further out, have you had any hedges out 2014, 2015 timeframe?

John Daniel Schiller

We did a decent amount of hedging during the quarter, we probably feel pretty good about 12 months out right now. What did we do, we went out to 15, correct?

David West Griffin

Correct.

John Daniel Schiller

So we got some barrels out at 15 now and we're historically about where we've been 75%, 85% in the current year hedged, with a little bit less than 50% on the next year then a little bit below 25% on the last year, if memory serves me. So we may look with some strength here, we may look at doing more stuff in out years.

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

But the December 17 hedge release is the latest stuff, correct?

John Daniel Schiller

December 17th? Yes. Correct. And Andy, also one big part of that CapEx is about $65 million for facilities.

Operator

Our next question comes from Biju Perincheril from Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

John, you had talked about horizontal inventory, I think, on the last call. I assumed the number was like 50 to 80 wells. And I think earlier today you mentioned West Delta alone it might be up to 40, if I heard that right. So is there an updated number for your total, sort of, total program?

John Daniel Schiller

Is there enough data what?

David West Griffin

An updated number of horizontal.

John Daniel Schiller

Yes, so If you could just take what I just told you there, I think in that original 80 West Delta was at 24, correct? Meaning we're getting close to 100. I would tell you we're doing a lot. We've been really increasing our technical staff. One of the reasons is I don't care how good you are in any way you shake it, when you have teams running a rig and trying to keep up with drilling and staying in front of it, there's not really not a lot time to go do other reconnaissance work that we're talking about. Each one of our teams is now getting backed with another reservoir engineer, another geologist is kind of helping doing behind the scenes mapping at some of these identification we're talking about. And I think you'll see over the next 6 months, we're going to get you a lot more information with how we're setting things up right now with just how big the playground is and how much running room we have in it.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

It sounds like most of that science work you're doing is at West Delta, so is there an opportunity to maybe accelerate that program at a second rig there?

John Daniel Schiller

We like the way you're thinking.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Well, and then maybe, if I could just look at this year's program, how many of these wells do you think you can bring online in fiscal '13? I'm just looking at horizontal wells.

John Daniel Schiller

Ben, how are we just looking at the number, how many wells do we bring online this year?

David West Griffin

13, the rest of the year.

John Daniel Schiller

We got 13 more on. Now some of those -- 4 of those were right in June. So they're not going to have a lot of impact but we should have 13 more on between now and the end of the year.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. And then if I can go back to Pendragon one question, I think you had mentioned you have some shallower objectives there starting in I think 7,000 foot depth and, now that the well's over 10,000, any color you can give on some of those shallower objective?

John Daniel Schiller

Yes. When we -- there was one amplitude, way up shallow, we actually found a shallow gas sand, but I don't think it's worth talking about. And everything else is, like I said, it's tied to the deep sands that were discovered on the north plain. And so we're about 2,000 feet from actually starting to see what -- we talked about 10 amplitude, we haven't seen any of those 10 yet.

Operator

[Operator Instructions] Our next question comes from Patrick Rigamer with Iberia.

Patrick B. Rigamer - Iberia Capital Partners, Research Division

Just wanted to go back to the reserve bookings on the horizontal, I think, previously, you had mentioned that the actual numbers you would book at year end might involve some discussions back and forth with the reserve engineers. Did you say earlier that the reserve engineers are now comfortable with the 1.2 on this first 3 and that's what you expect to book this year?

John Daniel Schiller

So the way the process works so we don't just rush everything at the end of the year. As we drill our wells, our Chief Engineer Floyd Bone [ph] and the team that are doing the drilling prepare a package and submit it so along the way so that they're already evaluating and giving us feedback and then we discuss it. And so those wells have already had that evaluation feedback and that's why we're to tell you from the low side of 1.2 million, which is Weimer to a high side of 2 million, 1.8 million, which is Big Sky. I think we all expect Hyden to probably be an even bigger number just based on how well it's producing from the zone it's in. It's been flat at 1,700 barrels a day for over a month now with no water.

Operator

I'm not showing any other questions in the queue at this time, gentlemen.

John Daniel Schiller

All right, I want to thank everybody for joining us today. We appreciate it. If you have anything else you want to talk about, follow up with Stewart offline and we'll circle back to you in case we need to. Thanks for your patience, I know it's a tough quarter but I'm telling you we have a lot of really neat things going on. And I got a lot of confidence in the group of people we got and the properties we bought. I think we're going to see some really good results and some very high EBITDA and cash flow as we move forward from here. Thanks.

Operator

Thank you. Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the conference. You may now disconnect. Good day.

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Source: Energy XXI (Bermuda) Limited Management Discusses Q2 2013 Results - Earnings Call Transcript
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