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Energy XXI (Bermuda) Limited (EXXI)

Q2 2011 Earnings Call

February 04, 2011 10:00 am ET

Executives

Stewart Lawrence - Vice President of Investor Relations and Communications

David Griffin - Chief Financial Officer

John Schiller - Chairman and Chief Executive Officer

Analysts

Joseph Magner - Macquarie Research

Ronald Mills - Johnson Rice & Company, L.L.C.

Joseph Bachmann - Howard Weil Incorporated

Eric Anderson - Analyst

Duane Grubert - Susquehanna Financial Group, LLLP

Jeffrey Hayden - Rodman & Renshaw, LLC

Richard Tullis - Capital One Southcoast, Inc.

Andrew Coleman - Madison Williams and Company LLC

Michael Bodino - Global Hunter Securities, LLC

Nicholas Pope - Dahlman Rose & Company, LLC

Operator

Good day, ladies and gentlemen. Welcome to the Energy XXI Second Quarter 2011 Earnings Conference Call. [Operator Instructions] I would now like to introduce your host for today's conference, Mr. Stewart Lawrence. You may begin.

Stewart Lawrence

Thank you, Amy. Welcome to the call today. Where we are, everybody's warm. Presenting today, we have John Schiller, Chairman and CEO; and West Griffin, Chief Financial Officer. We also have the executive team available on the line to answer 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 that we’ve described in our earnings release issued last night 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 our latest 10-Q to become better familiar with these risks and our company.

Now I’ll turn it over to John.

John Schiller

Thanks, Stewart. Good morning, everyone. You've got our entire management team on the phone with you reporting in from frozen Texas and parts of -- all over parts of the greater Houston area. So we'll be a little probably not quite as smooth as we usually are when we make some hand-offs today, but everybody's on the phone ready to visit with you.

We're feeling a bit of deja vu these days as history seems to be repeating itself almost to the day. A year ago when we did this call, we had just completed a bond deal, a major acquisition, and followed up with the announcement of the Davy Jones discovery. Fast forward a year and the story repeats, including yesterday's confirmation of our offset well at Davy Jones.

Right after reporting our first quarter results in October, we announced an equity raise that made our balance sheet pristine. What we intended at the time, we were looking at acquisition opportunities and needed to be prepared in case we were successful. Several weeks later, we were successful, our wishes came true, and we announced our acquisition of the Exxon Mobil assets on November 21.

We quickly issued $750 million of senior notes at the lowest rate and longest tenure in the history of the company. And we used those proceeds not just to close the Exxon deal, but also to retire our 16% notes and about 17% of our 10% notes. We also have converted 91% of our 7.25% preferred shares to common. The result is a transformed balance sheet, as well as a transformed portfolio of producing properties.

I'm not going to repeat the review of our newly-acquired properties, we did a full conference call on the deal, but let me update on what we've been doing since. Starting with the fact that we continue to be very impressed with the assets we've bought. We've identified additional opportunities already; for instance, we're putting a rig out at South Pass 89 to do recompletion work. Exxon had identified four. We're having a fifth re-completion to that, and we'll be getting that rig going here shortly.

First and foremost, we've been concentrating on putting together the operations team who will do the work on the new properties. Exxon Mobil continues to operate under the transition agreement, and we plan to be ready to take the reins by March 1. That entails hiring about 35 field supervisors and others as employees of Energy XXI, while bringing about 110 more field hands on board through our contractor firms that we've historically used. We expect about half of these positions to be filled by Exxon Mobil employees already in the fields. We've had a great response and are making good progress on that transition effort.

Back in office, we're going to add three new technical teams to work the new assets. That'll be about 12 professionals. The new teams won't be completely new. We'll actually be seating the majority of the new teams with our existing employees and back-filling behind them with some of the people we bring on board. Consistent with our approach in the past, most of the back-filling of our teams is going to be done by hiring people that we've worked with in the past. The new teams have already hit the ground running. They're poring through the field data to confirm opportunities Exxon's already identified, and we're finding more on our own, as I mentioned. I can tell you their enthusiasm for the properties is even higher now.

At the corporate level, we're folding these opportunities into our existing portfolio, and then we're ranking them for the capital program. We can already tell you that the second half of our year will see changes to what we presented earlier. We will soon begin the recompletion program, as I mentioned, at South Pass 89, that we expect to add about 3,000 barrels equivalent a day of production. Those volumes will help us since we've been stymied in our efforts at South Pass 49 and Main Pass 73, where we expected to have platform rigs installed by now.

.Basically due to the bureaucracy of our government, while we have been able to get permits, we're hung up on both of those structures with our ability to put a platform rig out there. And it's not a well permit issue, it's just a bureaucracy. But the problem with it is simply, they won't say yes and they won't say no and they won't make a decision. So what that's going to force us to do is we're picking up the Gorilla III rig for the Main Pass 73 area and we're going to drill our Ashton well and our Onyx projects that we showed you during our Investor Day back in March of last year. But we have delayed those and that's going to affect our budget, our production a little bit. At South Pass 49, we're continuing to work on getting them to finally say yes. We have a platform rig located, ready to go. We just need to get our government to move.

So we're going to tweak the program and put all this in. And we'll keep you apprised as we finalize all our drilling plans. We're going to provide you details on the overall opportunities at an Investor Day in New York, which we've tentatively set for May 13, so go ahead and put a save the date for May 13. By then, we'll have a good idea of what our final fiscal year '12 budget looks like.

The new properties certainly have us excited, and of course, we remain excited about our deep gas and ultra-deep shelf drilling. Let me give you a quick update on where we are on our major wells. Let's start with the one that has us most excited today, and that's our Valentine Pontiff well. That's the well we're drilling up-dip to the original Laphroaig discovery, Peterson #1. We're at 18,875 feet. I'm glad to say that, as of this morning, we have confirmed about 70% of the original 140 feet that we announced as being good with good porosities. It's actually extremely good porosities for the depth we're at.

We've also identified another 30 feet that was in both the original well and the sidetrack, but originally we thought it was probably going to be tight. Now that we have a porosity log, we realize it's also paying. We're right in the middle of the big pick zone on bottom. Hopefully, over the next day to two, we'll get through it. We'll get pipe set and we'll drill onto the last objective, which is up-dip in our book to the original sand that's produced 35 Bs in the discovery well.

At Davy Jones, we're at 28,230 feet. Back to drilling, as we discussed in our release yesterday, and making good hole. Blackbeard East, similar, we're at 32,638 feet as of this morning, drilling there. We've been knocking out some good days there. 150-foot drilling days below 32,000 feet. I would say probably better than any of us thought we could do. At Lafitte, we passed below 18,000 this morning. We're at 18,035 and drilling ahead there also.

The only negative news we have anywhere is we have TD'd the Plak [ph] Well. We saw the reservoirs. We saw the objective. We saw it where we thought we'd see it, but we didn't have reservoir quality sand. We only had about four to six foot of pay. The rest of the sands were tight. So we have plugged that well. The good news is we did it on budget for a cheap dryhole.

Last thing I'm going to talk about is how cold it is in Texas. I'll give you some sense on what it means to Energy XXI and the industry. For about the last week, we'd been consistently running about 46,000 barrels a day. The last two days, as the freeze has hit us, it starts affecting our gas lift for our oil wells offshore. Offshore -- or as a company rather, we've lost about 15% of our production in the last two days. And we're way far south in that chain. So think about what that tells you about what's going on in the Haynesville, and the Barnett Shales, Oklahoma wells. It's just cold, boys and girls. And when it's this cold, our wells in this part of the world are not configured to be able to heat everything. The gas wells, in particular, the freeze becomes a big of a problem for us. So it'll be interesting to see what happens on the supply side in the next couple of weeks. With that, I'm going to turn it over to West and let him talk about the financials.

David Griffin

Thanks, John. First, let's go through the changes to the balance sheet since September 30. As of September 30, we had total long-term debt of $710 million, and $110 million of 7.25% preferred outstanding. Interest expense plus preferred dividends create a total annual obligation of approximately $93 million versus annual EBITDA of $338 million, excluding the contribution from the Exxon assets.

Looking at our current balance sheet, taking into account the call of roughly 17% of the 10% notes that occurred in early January, we have total long-term debt of $1.3 billion, plus $297 million of outstanding preferred. The total annual obligation is approximately $129 million, up 38% from the stand-alone level. EBITDA, pro forma for the Exxon assets, was up 98% at $670 million for the 12 months ending December 31. So it's clear that Energy XXI's balance sheet is in a much stronger position.

Now let's look at the one-time items that affected the quarter's financial results. These are mostly easy to find in the income statement attached to last night's earnings release, since we put them in various separate line items. The first one, as you can see, are in our other income or expense, which are the bridge loan commitment fees of $4.5 million pretax or $2.9 million after-tax. Then there's the loss on the retirement of debt, which was $5.2 million pretax or $3.4 million after-tax. This is actually a net number, netting the gain from the original exchange of 16% notes for the 10% notes against the premium paid to retire the 16s.

The third item you see on the income statement is the costs incurred to induce conversion of the 7.25% preferred stock. That gets taken out below the income line, so the after-tax number is as shown, $19.8 million. That leaves about $1 million of expense unaccounted for, which is the after-tax amount of acquisition costs that had to be expensed through G&A.

Our daily volumes averaged 29,400 barrels a day, which included just 14 days of production from the Exxon properties. Those volumes contributed approximately 3,000 barrels a day for the quarter, so production from our core properties rose a couple of percent from the first quarter.

Given the oil focus of our development program, our production became even more oily in the quarter, at 70%. That and oil prices helped drive our revenues per BOE to more than $64 per BOE. Looked at another way, that 70% of production contributed 90% of our pre-hedge revenues during the quarter. The price of natural gas has become less important for us, which is why we monetized all of our gas hedges since September, collecting $47 million of cash. We have since begun layering in a few new gas hedges, which you can see in the spreadsheet posted to our website this morning.

On the expense side, a couple of things stand out. Total LOE, or lifting costs, were lower, helped by the increased volumes. The direct LOE rose a little, driven by the higher cost of the acquired properties. It's important to note that we do not expect that to be the case moving forward. We will see those higher costs again in the current quarter but, after that, they should start to come down. We fully expect to reduce the base operating costs for those fields by 20% to 30% compared with their historical levels. You should begin to see those savings in the June quarter.

G&A was slightly higher than expected due to the acquisition costs, but otherwise in line, even though stock-based compensation costs rose again due to the continued gain in the share price, which requires us to true up the accrual of stock-based bonus awards. The bottom line is that we've delivered EBITDA of nearly $40 of BOE, the highest in 10 quarters. Phrasing it another way, to better compare with the gas producers, that's $6.63 of EBITDA per Mcfe. It's good to be oily.

In fact, it's getting better all the time. We are benefiting from the widening of the grade spreads. The majority of our crude production is heavy Louisiana sweet, which has historically been trading -- or recently been trading at about a $10 premium to WTI.

Looking now at the hedging impact, we've put together a new sensitivity slide. This shows you that we have strong downside protection for the next year and a half while retaining much of the upside. And again, this is tied to WTI. Actual realizations could be higher to the extent that our oil continues to trade at a significant premium to WTI.

Now, I'll turn it back to John for the closing. John?

John Schiller

Thanks, West. Energy XXI is in a very special place right now. The past 18 months have been a whirlwind of activity, with two major acquisitions that have dramatically expanded the portfolio, a string of financing moves that have completely repositioned the balance sheet and a frontier exploration play that has us all excited.

Our core properties have the ability to grow, while spinning off large amounts of free cash, and the shallow water, ultra-deep program is getting very close to becoming a significant contributor to reserves and production. It all just keeps getting better. We're looking forward to our May 13 Investor Day so we can show you in detail all the projects we'll be pursuing. Between now and then, we'll have one more quarter to report with all of the Exxon Mobil production impact.

And now, before we open up for questions, I have one more thing to talk about. As you people know, we probably love our football in the South a little bit too much but it does consume us during the college football season. And unfortunately, on January 7, the Aggies didn't show up as good as they could, and the LSU Tigers proved their superiority. And based on recruiting yesterday, it looks like they're going to keep being a superior team.

So with that, I'm going to turn it over to the operator and we'll start the Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Jeff Hayden of Rodman & Renshaw.

Jeffrey Hayden - Rodman & Renshaw, LLC

John, just kind of a quick question for you. I know you alluded to some of the production issues just due to the weather. So kind of with that in mind and then thinking about timing of when additional capacity comes on, just kind of wondering if you can give us sort of a best guesstimate for sort of the Q3 and Q4 production numbers? And then, kind of second question, jumping over to Davy Jones, given what you guys have seen in the second well, how does that kind of impact or does it impact your kind of expectation of the prospect size?

John Schiller

Sure. I think for Q3, we're probably looking somewhere between 43,000 and 46,000. We showed we had a good month in January. We could go off the top of that if all the things go right. But let's see how our recompletion program works. Let's see how quickly we get this Pontiff well on production, which you know that's going to be a big, solid contributor to production. For the fourth quarter, probably a little early, but we'd probably be looking -- we think we can exit our fiscal year in the high 40s for sure. With regards to Davy Jones, there's a lot of moving parts going on there. We continue to evaluate both the original log and the new logs. We're formulating a lot of opinions. I would say that I'm probably even more upbeat than I was before in terms of what the potential of this stuff is, for various reasons. As we continue to confirm the technical analysis, I think you're going to find out this is every bit as big as we continue to tell you. We're drilling wildcat exploration wells. We're 2.5 miles away, so the sand's a little shellier, not quite as clean, consistent with going up-dip on a big structure. We've always had, with our seismic guys, modeling going both way from the sands were laid down and then the faulting occurred -- I mean the uplift occurred to the uplift was occurring as the sands were being deposited. Based on what we're seeing on this well, it tells us that second model is probably more correct, that simultaneous with deposition occurring, the structure was growing. So you're going to have a little bit different sand quality to the southern end of [indiscernible] resource versus the north and east and west end. So right now we feel really good about it, bottom line.

Operator

Our next question comes from Ron Mills of Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

As you go back to your reserve release late last year, Netherland Sewell had kind of done a 5 tcf contingent resource potential. Based on the information yesterday and your answer to Jeff's question, it sounds like what this does is make you feel as confident as before, if not more, at the numbers that you-all have been putting out, number one. And then number two, you've talked about being able to collect enough data in this well to book reserves at the end of your fiscal year this year. What are the key determinants? And how are the bookings determined based on those determinants?

John Schiller

Yes. First one, I think if we called Netherland Sewell right now and showed them all the data, we'd clearly have that number or a bigger number out of them for the 3P. So I feel very good on the 3P. In terms of what we need, the logs are good. Obviously, we're going to want to get a complete porosity pass through everything. That'll help. And we'd like to get some pressure points. Those are the things that are going to go the furthest with Netherland Sewell in terms of booking proved reserves. So we're working with them right now. The main thing is keep drilling. What Jim Bob said yesterday in his release, the Tuscaloosa may be something totally different and even more spectacular. So we get the well to TD. We'll be open hole all the way. If and when we decide to run the pipe, we'll go back and start getting all the data points we can get.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then at Laphroaig, the discovery that you've made, I know what the target size has been mentioned by McMoRan, on the pay that you've seen, plus the incremental 30 feet of pay with porosity, it sounds like at least the direction or the potential size is higher. Is this structure maybe bigger than you thought or what's your current outlook on that well?

John Schiller

Yes. We think as the whole picture comes out and we put it on production, that you're going to see it's a fairly significant discovery. Ron, I will tell you that we have slightly different interpretations. And that it's just a matter of getting this well on. I think we'll probably want to drill a development well up-dip fairly soon. Let us get all the data. We're logging with LWD right now. And that may be -- that's probably all we're going to get. We're probably going to turn around and run pipe, just so we make sure we don't get in a bind like we got in last time we saw this sand. But yes, we think this is a fairly significant discovery with a lot of potential. And the obvious reason for that is we've got structures working. We got a trap that's working and loading up sand.

Operator

Our next question comes from Duane Grubert of Susquehanna.

Duane Grubert - Susquehanna Financial Group, LLLP

John, on the Exxon Mobil redevelopment project inventory, can you compare that to the spec you had pre-Exxon deal and tell us, if there's anything different about those fields that would make that roster of re-development projects similar to, better or worse than what you had before?

John Schiller

No, clearly better, Duane. I mean, our preliminary re-ranking of the projects -- and we've got to go through and kind of do apples-to-apples. When Netherland Sewell's done their work, it's not necessarily apples-to-apples with our stuff. But right now, anywhere from 70% to 80% of our top 20 projects become projects from the Exxon assets. And that's not surprising. It's what it should be. We're the first-time an independent's on these fields as opposed to every other major field we have has gone through another independent before we have it. That's what's got us so excited about Exxon. You look at what we've done on these large fields coming behind other independents and think about what we ought to be able to go coming behind a major, which have a totally different look at overhead and costs and drill dollar cost to add barrels.

Duane Grubert - Susquehanna Financial Group, LLLP

And then prior to the Exxon deal, you guys had talked about, long-term, having capacity maybe to get your existing portfolio up to something like 40,000 barrels a day or more. With the Exxon stuff in there, is there a long-term number that you would throw out to compare to that old number?

John Schiller

Yes, I mean, I would say we presented a strategic plan to our board, a three-year strategic plan. And given them the high 50s and close to 60 is very much a doable thing over the next few years.

Duane Grubert - Susquehanna Financial Group, LLLP

Switching gears over to the shallow water, ultra-deep, have you had any incremental indications to encourage the idea that you might have liquid content in either the Davy Jones or the Blackbeard project?

David Griffin

No, Duane. Nothing that would tell us anything like that, one way or the other.

Duane Grubert - Susquehanna Financial Group, LLLP

And then finally, I've had a lot of people asking the question, "Gee, McMoRan said they've got 100 feet of pay in the well," and I recognize the log wasn't effective over the whole zone, so I consider that sort of as a minimum. A, is that the right way to look at it? And b, could you comment on some sort of scoping theme about, is 100 feet of pay something that just makes the development smaller if you were only to have 100 feet of pay? Fewer wells or longer production life? Or how would you think of suggesting us to think about if there is less net pay on the sort of size of the field?

John Schiller

Yes, I think if you go back and listen to what Jim Bob always cautioned, the one thing he's always talked about on drilling big discoveries like this is you know never know for sure whether you've seen the full section, i.e., is the first run you logged all the way to the sands that were laid down without fault? Is there a fault in there you don't know about? Et cetera. A decent chunk of the difference between 200 and 100 feet is there's some missing sand. So we got to keep working that. We've got to figure out if our seismic guys can map faults in there to explain where some of the sands went. Or did they to shell out? And those give you two different answers on the overall. Kind of back to what I alluded to earlier, Duane, with some of the petrol-fluid [ph] work we're doing, there may very well be zones we haven't been talking about, as I've shown some of you, that are full of gas and will end up contributing. So I think at the end of the day, talking about 200 versus 100 on the grand scheme of what we know is round off to how big this thing is, personally.

Operator

Our next question comes from Nick Pope of Dahlman Rose.

Nicholas Pope - Dahlman Rose & Company, LLC

A question about the new CapEx budget. I guess with the shift from what you guys had been talking about whenever you acquired the Exxon assets, I guess what's the bulk of the move there in CapEx? And I guess what do you expect in terms of -- what will we see in terms of production I guess impact from the new asset, spending that's in there?

John Schiller

Yes. I mean the largest chunk is the re-completion of work at South Pass 89. It's like $25 million.

David Griffin

It'd be around $20 million.

John Schiller

$20 million. And then, we're doing some facility work, some pipeline work, that type stuff, that's about another $10 million or $12 million. So that large piece right there is all directly related to Exxon. Then we got about $20 million with the ultra-deep, assuming we drill another well and some things like that. So that's the main part. So some of it's got production impact. I think conservatively, we stick with what I said earlier, Nick, 43,000, 46,000 for the next quarter. Let's see how bad the weather hits us. Let's see when we get out there, get the re-completions -- we're not going to do the re-completions until March 1. We had a lot of debate, but at the end of the day with Exxon, if they did this work, we weren't going to have any control over how it got done, and we decided from a liability standpoint and everything else, it would be better off waiting until we took full control on March 1. So that work's probably not going to have an impact. And then again, like I mentioned earlier, Pontiff is -- that's, for our interest, is like a solid 1,000 barrels a day if it produces like the last one. That's just flat for 18 months or maybe even two years, as big as some of this is. And so we got to see what all the timing is on that and then we could give you a better guess. But my guess is most of that starts hitting in the fourth quarter, not the third quarter.

Nicholas Pope - Dahlman Rose & Company, LLC

.

And then with the production testing equipment that you have on order, I mean, it's always been scheduled for Davy Jones #1 to be the production test, I think with the potential that if something kind of moved ahead of it, maybe that it could be moved to do a different well. But I mean, at this point, with all the data you know, is it still Davy Jones #1 is going to be where the production tests are going to take place before year end?

John Schiller

Yes, but I would caution you, production tests, it's a completion, Nick. There's no production tests involved. We're going to run the tubing, run the packers, nipple up a tree and go in there and perforate and flow through a tree. So it's making a completion. All that's still on track, as we talked about. Again, not to beat up on our government too much because I could do that all day, but the delay there is they want us to have a 25,000-pound BOP stack, together with a 25,000-pound tree. Since we'll never -- no one in their right mind would ever get on a well, as you know Nick, with 20,000 pounds pressure on it. We'd kill all the wells before we get ever get on them. So it's a bit of an overkill, but it's the one thing they came back after they reviewed everything. So we're going to honor their request and go with it. But everything's on track. I don't see right now, with what we know, moving to #1 versus #2 would gain us anything.

David Griffin

The two make take more than half, but we don't have a three.

John Schiller

So two -- remember, we're drilling big holes to set up for a higher rate. So as far along as we are now, it'd be a little tough to swap over the equipment we have and make it work, unless we want to sacrifice rate. And we spent an awful lot of money to get a big hole, so we're not going to do that.

Operator

Our next question comes from Eric Anderson of Hartford Financial.

Eric Anderson - Analyst

I wonder if you could comment a little bit, John, about the shows in the Frio that McMoRan discussed maybe a month or so ago, and what that possibly might mean for estimate across the Blackbeard basin in terms of total resource size.

John Schiller

Sure, I mean, we saw two sands there. Both of them had 16% porosity, 31,700, 31,900 feet. The Frio -- if you grew up in south Texas, Houston, working the oil fields like I did, the Tom O'Connor field, the Hastings oil field, the big wells at Louisiana, and there's is a whole series of large oil fields and gas fields along the Gulf Coast that are all Frio. And we're now drilling out on the shelf. We know when you go to deepwater, you're going to see the Frio sands, but we certainly expect there to be some sand somewhere on the shelf, along with everything else we've been figuring out as we drilled this half dozen, not quite half dozen wells. So it's big. I mean, it opens up a whole new play. We never saw -- to clear up some confusion, in Blackbeard West, while we did drill into the Oligocene and see pay, it was never the Frio-aged sands. Kind of like when we drill the Eocene and find the Wilcox age, a little bit different. Or the Cretaceous and we're going to look for Tuscaloosa sand. So seeing the Frio sand is a big deal. They've been highly productive, very prolific reservoir. They're obviously maintaining quality here, even at that depth. So we're working it hard. The seismic guys are seeing what they think they can model and tie to it, and we'll go from there.

Eric Anderson - Analyst

With regards to DJ #2, do you expect to go deeper than the planned 29,900 Td as you have in Blackbeard East? Or will that just...

John Schiller

I will tell you right now, if our correlations are right and the section we see looks like how the Tuscaloosa drilled in south Louisiana, then I would tell you now, I think we've got a good chance of being through the Tuscaloosa sands by the time we get to 29,950.

Eric Anderson

Where do you have the Rowan EXL 3 rig scheduled to go when it gets its permit?

John Schiller

McMoRan's going to operate that rig, and we really got to save that question for them. We haven't really talked that much. I think they've got a well they're going to go with it first, but I could be wrong.

Operator

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

Richard Tullis - Capital One Southcoast, Inc.

John, after the press release from McMoRan yesterday related to Davy Jones, how much of the four offshore blocks -- I guess it's roughly 20,000 acres -- how much of that structure do you think has been derisked at this point?

John Schiller

I will tell you that there's 7,000 acres up-dip of us. At the same time as we've done more and more, I would say that it's probably in excess of 50%.

Richard Tullis - Capital One Southcoast, Inc.

How about, what are you hearing back from -- I guess it's the BOEM, related to the installation of the platform rigs at Main Pass, South Pass. I mean, what are they looking for there? What kind of timeline do you think you might be expecting?

John Schiller

Well, that's the whole issue, Richard. They won't say they need data, they won't say no and they won't say yes. I wish I could answer your question. They're just afraid to do anything. And we're working it. We're trying to move it forward. With everything that's gone on and the amount of oversight they're seeing, it just slows the process down significantly. We've given them the raw data. We've given them our engineering numbers off the raw data. They just need to look and make the counts and say ,"Yes, " "No", or "We need more data." It's to the point now that the guy that owns the platform rig we were going to use has gone to them and said, "Hey, I just laid off my whole crew, and I've been holding them on my payroll for three months thinking you guys would make a decision." And so little comments like that. We're trying to move it along. But as you well know from what's out there, now is not the time to try and pressure up on them.

Richard Tullis - Capital One Southcoast, Inc.

Given that sort of red tape that you're experiencing now, what sort of -- when do you have to have the equipment available for them to start initiating their inspections and test of the tree for Davy Jones? And how much time are you giving them to basically carry out all their maneuvers before being able to say, "Bring it online at calendar year-end?"

John Schiller

Richard, on that end, I mean, we're meeting with them on a regular basis. As we roll out the final equipment, it's actually Baker or Cameron's going to test it within their facilities. But then it actually goes to a third-party that's authorized by the BOE. They have the right to be there and witness it or they can go off the BOE certification. But that's a fairly routine step that, to date, we don't see any issues with any of it. They've been sitting right there with us. They know what we're doing. As I said, the BOP was the big thing that they took exception to. And I'll just tell you, there's a lot of 20,000-pound well head's been put in without the benefit of the 20,000-pound tree, and leave it at that.

Richard Tullis - Capital One Southcoast, Inc.

And then just finally for me, what's the estimated timeline for upcoming ultra-deep news, well results or feet? Blackbeard East, what are we expecting there as far as timing?

John Schiller

Yes, I mean, obviously, Blackbeard East and Davy Jones are both in the position where it could be a week from now, it could be a month from now. I mean we're both well into the zones and anything can happen, and I would announce that. Lafitte, I think we got to go about 2,000 more feet. One pipe program then or two?

David Griffin

We have two to get below.

John Schiller

So we have two more pipe sets. So you're realistically -- I mean, absolute best case, a month, and likely best case is six weeks before you start drilling below the salt well and go into the Miocene sands.

Operator

Our next question comes from Joseph Bachmann of Howard Weill.

Joseph Bachmann - Howard Weil Incorporated

John, have you guys picked out the down-dip location for the Davy Jones, the next Davy Jones well north of the original well?

John Schiller

We have not.

Joseph Bachmann - Howard Weil Incorporated

Is that kind of the direction you would be going with the next well or are you still trying to figure that out?

John Schiller

Clearly, from the release yesterday, there's a lot of evidence that says we need to go over there. We haven't had a joint meeting of the partners, technical meeting, to talk about it yet. But we got to have all that and go through the formal process and figure out what location makes the most sense for the next well. It's just still a little early, Jeff, to do that.

Joseph Bachmann - Howard Weil Incorporated

And the last question was on Crete. And just kind of -- if you can talk a little bit about that prospect and if you have the permit for them? And what's you're thinking on when that one's going to spud?

John Schiller

The key thing there is the more we look at it, the cheaper the dry hole is, so it's become an $11 million dry hole estimate. We like all the potential. We're still fine tuning the seismic. That's taking a lot longer than I mentioned last time because of the turbo and froth going right through our asset. We have not started the permit process, don't expect it to be any issue at all. We're getting ready to start the permit process, Jeff, so it could be anything from a May spud to a July spud, but somewhere in there is what we're shooting for.

Operator

Our next question comes from Michael Bodino of Global Hunter Securities.

Michael Bodino - Global Hunter Securities, LLC

A couple questions on Laphroaig. How many wells do you think it's going to take to fully develop that? I know it's a little bit early to get into that.

John Schiller

Yes, let me say that I think you could delineate it with probably two more. I think you can drill two more wells and figure out the total potential size of it. Then you'd figure how many wells it takes to develop it. Remember, when drilled discovery well, what we call the MA-11 sand, we had another sand below there that was really clean but wet. But we don't know what it's going to do yet when we get to it. So if we're up-dip, we might start catching gas there. What we do know is once we cross the fault, every sand we've seen is loaded up, which is the way transfer is supposed to work.

Michael Bodino - Global Hunter Securities, LLC

That was going to be my next question, is you said you were going to set pipe here, move forward with completions. Would the next well be in the same fault block, would it be a different fault block to test the deeper sand?

John Schiller

Yes, it did. Yes and yes. I mean, Mike, there's some competitive nature. There's some people offset there. That one's a little hard for us to talk a lot about.

Michael Bodino - Global Hunter Securities, LLC

It was pretty exciting when you dropped it in the release, I wanted to dig into a little bit.

John Schiller

I think you can tell from the way I lead with it and talked, we think we have something fairly significant to our company there. But we got to be careful and make sure we get everything the way we want it, first.

Michael Bodino - Global Hunter Securities, LLC

Any thoughts on what you'd expect these deep wells in development to flow once completed?

John Schiller

Yes, I mean, we flowed 40 minutes on the first well, 700 barrels of condensate. I can tell you right now with what we have here, we'll do better than that. It's going to be up to the tubing size we run. When you talk about development wells and delineation wells, that's something we have to look at it. It would not be very hard to do, to drill to this big sand that we're in the middle of right now, go up-dip and run a bigger pipe program so you can make 75 million a day. The sand will clearly give off those kind of flow rate.

Michael Bodino - Global Hunter Securities, LLC

You talked a little bit about production guidance. Any further thoughts on these operating expenses in the March quarter? How those things are shaping up, given some of the operations you're undertaking right now?

John Schiller

West?

David Griffin

Yes. In March quarter, we anticipate that, basically, you're going to see somewhere sort of LOE numbers to what you saw this last quarter. And then after that, you're going to start seeing a decline. During the March quarter, as you may know, we're still in the transition period with Exxon. And so as a consequence, pursuant to the purchase sale agreement, we pay them about a 12 1/2% fee or premium on our expenses. So we're incurring that while at the same time staffing up, et cetera. So we're not going to be in a position to actually bring down those costs until we take over our operations here sort of at the end of February or early March. So we'll start, at that point, start realizing some economies.

Operator

Our next question comes from Joan Lappin of Madison Williams (sic) [Gramercy Capital].

Joan Lappin

It's Gramercy Capital. On the Frio, I am not familiar with these onshore Frio production sites. And do they produce gas? Or do they produce oil? Or do they produce something in between?

John Schiller

Actually, the ones I was talking about are big oil fields that generally would have all done over 500 million barrels, some as many as 700 million barrels. If you remember, Hastings was an Amoco discovery. Tom O'Connor was an Exxon Cullen discovery. Then as you move into Louisiana, on the border, there's always been a Frio play there that I believe is gas. And then my knowledge, because I didn't grow up in Louisiana, I'm a little less knowledgeable on the big Louisiana fields, but you've got oil and gas.

Joan Lappin

So we don't know what we have yet?

John Schiller

At that depth, what we've seen to date, we would fully expect it to be gas.

Joan Lappin

But there could be some other goodies in there?

John Schiller

Yes.

Joan Lappin

Now in terms of bringing on these new teams that you're busy hiring and so forth, how fast is that going to happen? And how much additional expense is that going to require?

John Schiller

Yes. I mean, we've already made a couple of hires. And we're in the process of interviewing many people right now. That's all moving ahead. Tom's online. But I would think, probably in the next couple of months, we'll have all that in place. I think, overall, we're looking at somewhere around $2.5 million, $3 million G&A.

Joan Lappin

Now in terms of going north, and looking at some of the older maps that have been shown in some of the cartoons in previous presentations, is this pushing toward John Paul and England? Is that the neighborhood we're talking about?

John Schiller

Yes, that's funny, for a lot of reasons. There's two things we're talking about there, Joan. First and immediately, what Jim Bob was talking about in his release, is that on the north side of Davy Jones structure, if that structure was in fact growing as the sands are being deposited, which is what you would be led to believe by what we saw on the south side, then this north side -- typically when you look at all the big fields along the Gulf Coast that are four-way structures, your north side has tended to have your thicker sands because that's where your source is coming from. So think of it as bouncing up against that mountain and then spreading around. But as you allude, if those other structures were there first, they also have to negotiate those. So it does tell you some positive things about what you might want to do with regards to John Paul Jones and England.

Joan Lappin

Now those are in really shallow water, are they not?

John Schiller

Yes, ma'am.

Joan Lappin

So you need barges?

John Schiller

We think some of that can be drilled with barge rigs. In fact, I think if you talk to McMoRan, they're modifying a barge rig now for the hook load that we need so that it can work for us.

Joan Lappin

Now, would you need these humongous blowout preventers for that too?

John Schiller

Not while drilling them right now. They're just worried about once you have a live wellbore, so no. We'll probably drill those with either 15,000 or 20,000-pound BOP, like we have. Remember, the issue when you take a kick, is that you always have open holes. So a long time before you ever exceed your pressure at the surface, something has given away down hole. That's why you don't need as high a pressure equipment on the BOP stack. And yes, I mean, the barge rigs, the big thing is the hook load. With barge rigs, we can move alongside all the barges we want to handle pipe and pumping. And yes, whatever we need to do, we can augment with another barge tied up. So you don't need huge amounts of deck space. What you need is derricks and elevators that can handle the hook loads.

Joan Lappin

And then lastly, as far as Blackbeard East is concerned, so you're saying you're making 150 feet a day lately?

John Schiller

We've had a couple days where we've done that, but we've been north of 100 every day.

Joan Lappin

So it won't take that long to get to 34,000. Are you going to China or...

John Schiller

No, we're just slow and steady advancing on 34,000. We like what the Paleo's been doing. The Paleo tells us right now that we feel very good that we're going to get -- we're already in the Eocene and we're looking to get to the Wilcox sands. And we feel very good that, that's going to happen.

Operator

Our next question comes from Andrew Coleman of Madison Williams.

Andrew Coleman - Madison Williams and Company LLC

Thinking about the target you set in your long-term plan of near 60 MBD, can you give a flavor for what sort of, I guess, growth on CapEx? Is that kind of projecting sort of similar investment on an F and D basis that you had done in the last couple of years on the investment?

John Schiller

Yes, Andrew. That's based on kind of a low case, which runs just shy of $400 million in capital, average, over the next three years. So as we learn more and we see more opportunities at Exxon, obviously, we're going to put the capital to work, and you'll see some corresponding rate increases. What we're kind of quoting is pretty much just doing what's out there in the 2P world. There's not really any exploration impact from either the Exxon assets or anything else in that number.

Andrew Coleman - Madison Williams and Company LLC

So it's safe to assume it's fairly weighted towards kind of just some basic blocking, tackling and recompletion sliding fees and just part of development?

John Schiller

Yes, development wells and drilling puds and all that stuff.

Andrew Coleman - Madison Williams and Company LLC

And I guess stepping to the Davy Jones asset, do you think that -- is it the next logical step to assume that if we were to drill another well, that it'll be coming closer to the source? Or is it still -- you guys are still evaluating all the seismic and stuff before you and McMoRan I guess make that choice?

John Schiller

Yes, I think first and foremost, it depends on what we see in Tuscaloosa, which could change everything in terms of what you're doing for your next well. If what we're going after is a Wilcox -- the next Wilcox where we drill, let's put it that way, yes, I think you move around to the north towards the source and see what you have over there. But you can kind of remember that's what we've always said. We triangulate, the well we have on the east, the well to the southwest, the well over on the north side, and then you're pretty much ready to get the development drilled.

Andrew Coleman - Madison Williams and Company LLC

And how much, would, I guess, having the Wilcox data point over to the east there, Blackbeard East, how much would that help on your regional interpretation and on the seismic that you're able to get down through there?

John Schiller

Yes, it'd be very significant for the overall play. It's probably not something that we're going to put on production next year. It may surprise us. But right now, we'd say, with the pressures I think we'd see, we wouldn't get it on production real quick. But it's invaluable data point when you're 90 miles away from your last Wilcox. You've got the well that Stone and Armstrong are drilling onshore. You start getting enough data in the Wilcox and you start really thinking a little bit more about understanding it and what you know and don't know and how really big the play can be. So it's a critical data point. And when we spud the well, that's -- the consistent thing at Blackbeard East has been that structure's continued to get taller and taller on us. And zones that we thought we were going to have to get to 36,000, 37,000 to see, we're actually quicker now. So right now, it all looks good for seeing a Wilcox and being a very significant data point for us.

Andrew Coleman - Madison Williams and Company LLC

Then just one, I guess, geography question. The Laphroaig well was drilled, I think -- was that Vermillion Bay, if I remember it correctly? And if so, how close is that? Because that was with a barge rig, I think. How close would that be to Davy Jones?

John Schiller

You're talking about the Laphroaig well?

Andrew Coleman - Madison Williams and Company LLC

Yes.

John Schiller

The Peterson and the Pontiff that we're drilling now are actually in Bayou Corridor, I think, and then in St. Mary's Parish. Where's the locator map? It's to the northeast.

Andrew Coleman - Madison Williams and Company LLC

So there's a chance that you guys start filling in that gap with potential targets there in the future?

John Schiller

Yes. I mean, there's some industry scuttlebutt going on out there, there's another big well in South Louisiana that's going to 21,000, privately-operated. They've hit three of their four pay sands. They crossed the fault. First sand loaded up, second sand was wet, and the next two sands have loaded up. And they're still not to their main objective. So you're seeing a lot of that deeper drilling along the coast there and people starting to find significant things. And I think you'll see that trend continue to open up.

Operator

Our next question comes from Derek Jumper [ph] of DW Investment Management.

Unidentified Analyst

I was wondering if you could just kind of talk to us about what your tax position is? And in terms of cash taxes, are you a cash taxpayer now? If not, when will you become a cash taxpayer, what's your NOLs?

John Schiller

West, why don't 'you handle that?

David Griffin

Sure. We are not a cash taxpayer. In fact, the reason for that is that we get the benefit of tax deductions associated with our drilling program, and that really shelters our income. In fact, has created a fairly significant NOL for us. We've utilized a fair bit of that NOL when we did the bond exchange and a couple of other things. But currently, we're not a taxpayer. Our effective tax rate is about 15.5%, if that's kind of what you're looking for in terms of modeling. But we're not currently a taxpayer. And based upon our CapEx plans over the next several years, we don't anticipate necessarily becoming a taxpayer. Obviously, that depends, to a certain extent, on what happens to commodity prices. But we hope at some point, with the rising commodity prices, we could become a taxpayer. But with these current CapEx plans we have, we don't anticipate becoming one.

Operator

Our next question comes from Joe Magner of Macquarie Capital.

Joseph Magner - Macquarie Research

The CapEx bump that was announced for the remainder of this fiscal year, does that anticipate any of the wells that could be drilled based on success, either your appraisal well at Blackbeard East or another well at Davy Jones or another well at Laphroaig? Or is that just addressing the kind of day-to-day recompletion, work-over type activity?

John Schiller

Yes, about half of it is Exxon assets-related. And then there's a piece in there for exactly what you described, another well on the ultra-deep. And then some moving in and out of like Ashton and those projects that are going to cost us a little bit more, the Gorilla rig and things like that.

Joseph Magner - Macquarie Research

And then the discussion of how many of the Wilcox sands have been found in the second well, three versus the four that were found in the original discovery well, the cartoons in your presentation shows four or five different Wilcox sands. Do you have enough information to identify which one is not present in the second well or is it too early this time?

John Schiller

No, I think using McMoRan's terminology, it's what they call the Wilcox D, which is kind of the middle sand to five. You have a B, a C, a D, an E and an F. And it's the D that's missing in this well.

Joseph Magner - Macquarie Research

In terms of the rig needs you have, you've got the three wells currently operating ultra-deep. You talked about picking up the Gorilla III, one to two platform rigs, perhaps a barge rig. Any other rigs that you might need to carry out the plans you've got in mind?

John Schiller

Yes. I mean, we're going to pick up the Gorilla III for two wells. If we ever get South Pass 49, I'll tell you we're going to pick up a private platform rig. Platform rig to do South Pass 89. So we're working on who's going to do that work. We're going to pick up an Ensco rig to drill a well out at Main Pass 61. And that's the known rigs right now that we're looking at near term.

Andrew Coleman - Madison Williams and Company LLC

And that's another platform rig, that Ensco rig?

John Schiller

Yes, a platform rig to do the Exxon recompletion. It's a platform rig for South Pass 49 to do the old Energy XXI drill work. Ensco's a jack-up. I'm sorry.

Joseph Magner - Macquarie Research

And then between now and the May update, you're talking about having the analyst meeting, are there any other decisions that could be made -- aside from expected results from the ultra-deep wells currently drilling, any other decisions that could be made between now and then? Or is that really the next opportunity for you to provide us with a kind of detailed review of your plans? Just thinking about the Blackbeard West has been hanging out there and some other possibilities, some of these wedge wells and just your flank wells. I'm just curious what might come up.

John Schiller

I think as we see some things, the Pontiff well, getting the Td. What happens at Davy Jones to Td with the Tuscaloosa, you're going to see more news before we talk. Hopefully, we'll have some update on the first recompletion at Exxon and things like that. We'll just have to go and see.

Operator

Our next question comes from Brenda Desouza [ph] From Seymour Pierce.

Unidentified Analyst

Just a couple of questions, one is on the OpEx. It was at $47.84 million in the quarter, and you guys did explain something, it won't go down because of this 12 1/2% premium to Exxon Mobil. So is it going to be around the same level or maybe slightly lower in the next couple of quarters? And also, when does it go down? I think I just missed that part.

John Schiller

Yes, I think West talked about -- we expect this quarter that we're currently in, you probably won't see a lot of movement down because Exxon's operating the assets until March 1, and we're paying that 12.1/2% fee you alluded to. After that, in the next quarter, our last quarter of our fiscal year, you should start seeing our LOE start to trend down as we impact it with the things we're doing on the Exxon acquisition assets.

Unidentified Analyst

On the G&A front, I see you guys did about $15 million. But as you guys explained, $1.5 million was like a one-time non-recurring thing. I'm just trying to understand, what kind of base figure on G&A we should take, because that currently is scaling up, and I think you said $2.5 million more in G&A?

John Schiller

Yes, West, you want to chime in? But I mean, from our end, this is the second lowest quarter we've had out of the last five. With the rising stock price and the way we compensate our people heavily based on the performance of the stock, that number's a little hard to peg. Our base number, West, without stock appreciation, is what, do you think? $4 a barrel, $3.5?

David Griffin

Yes, the base was anticipated -- absent any stock-based compensation, et cetera, was around $17 million.

Unidentified Analyst

On depreciation, just what kind of rate are you using going forward? Because I saw that the rate was about 11% annualized for this quarter, and I think historically it's been slightly higher. So I'm just trying to understand on the depreciation front.

John Schiller

West?

David Griffin

I couldn't understand the question. Was there an 11% increase on depreciation, did you say?

Unidentified Analyst

No, I said depreciation was 11% of the assets, like 11% of the net assets. Now, I'm just trying to understand like going forward, should I be modeling on that rate or slightly above that?

David Griffin

What we do when we do our DD&A, we update our DD&A rate at the end of every quarter and then utilize that DD&A rate for that quarter. So we sort of back-cast, if you will, the DD&A rate for that quarter. So the DD&A rate that we had for BOE in December will be the same as it is for March, absent any additions or anything else with respect to reserves.

Operator

We have a follow-up question from Ron Mills of Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

On Davy Jones, the comment I think is probably one of the more important and you can support this or not, is the impact of the continuity of the sands 2 1/2 miles away. And how would you explain in layman terms exactly what that means, given the amount of distance, especially in the Gulf of Mexico?

John Schiller

2 1/2 miles in anywhere is a long step out. The fact that we're seeing the sand, the fact that we have sands, coupled with some things that we're working on the technical side from a vertical connection, tells us, as I alluded to, I think we have a very large gas source and gas reservoir here. So worrying about the specific 100 feet right now is a bit more anal than it should be given all the other things we know. I mean, as I said, Netherland Sewall, I promise you, the data we have, it's probably going up, not down, under the 3P.

Ronald Mills - Johnson Rice & Company, L.L.C.

West, just one quick clarification. When you talk about LOE and the direction, are you talking about on a unit basis versus the second quarter or on an absolute basis?

David Griffin

On an absolute basis. It goes up. You could see a little bit of improvement there in terms of the LOE.

Ronald Mills - Johnson Rice & Company, L.L.C.

But your LOE for the March quarter should be, on an absolute basis, significantly higher than the second quarter just because you have the full quarter impact. Correct?

David Griffin

We'll have a full quarter impact, but the other issue we'll have is that we're going to transition from Exxon operations operating those assets to us operating it sometime at the end of February. So we should get some improvement towards the end of the quarter associated with that to counterbalance.

Ronald Mills - Johnson Rice & Company, L.L.C.

But you had $45 million of LOE for the second quarter, and you have an incremental 20,000 barrels of production. So you'll have, on an absolute basis, will be above the $45 million.

David Griffin

Yes, absolutely. I was talking about it on a pro forma basis, if you take Exxon and Energy XXI during the December quarter.

John Schiller

Ron, said another way, your absolute's going up, your price for barrel's going to go down.

Operator

Mr. Lawrence, I'll hand the call back over to you.

Stewart Lawrence

Actually, we'll turn it over to John for closing comments.

John Schiller

Thanks, everybody. We appreciate you joining in for the call. Look forward to updating you with some more good news between now and the next time we get together. If not, we'll see at various conferences over the next coming couple of months from. See you next to Howard Will and on. So thanks for your attendance. Adios.

Operator

Thank you. Ladies and gentlemen, this concludes the conference for today. You may all disconnect, and have a wonderful day.

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