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Energy XXI (Bermuda) Limited (EXXI)

F4Q2010 Earnings Call Transcript

September 8, 2010 10:00 am ET

Executives

Stewart Lawrence – VP, IR and Communications

John Schiller – Chairman and CEO

David Griffin – CFO

Analysts

Steve Berman – Pritchard Capital

Duane Grubert – Susquehanna

Nicholas Pope – Dahlman Rose

Neal Dingmann – Wunderlich Securities

Richard Tullis – Capital One South

Joan Lappin – Gramercy Capital

Jeff Hayden – Rodman & Renshaw

Phil Dodge – Tuohy Brothers

Don Chris [ph] – Johnson Rice

Alan Sinclair – Seymour Pierce

Operator

Good day, ladies and gentlemen and welcome to the Energy XXI Year-End Conference Call. At this time all participants are in a listen-only mode. Later we will conduct the question-and-answer session and instructions will follow at that time. As a reminder, this conference call is being recorded.

I would now like to introduce your host for today’s conference, Stewart Lawrence, Vice President of Investor Relations and Communications.

Stewart Lawrence

Thanks, Gerome. Welcome to the call today everybody. Presenting today is John Schiller, our Chairman and Chief Executive Officer. Also in the room, we have West Griffin; Ben Marchive, Todd Reid, Hugh Menown, making at the management committee. We would get some additional executives in the room, to help 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 included among others, matters that we’ve described in our earnings release 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, 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, which will be filed later today and our latest 10-Q to become better familiar with these risks and our company.

Now, I’ll turn the call over to John.

John Schiller

Thanks, Stewart. Good morning, everyone. Our audited financials released yesterday afternoon, there should be no surprises since we’ve preannounced all the key data a few weeks back. So we’ll skip the formal discussion of the quarter’s results this morning, although we’ll certainly be available to discuss them in the Q&A session.

To start let us look back at the year we wrapped up on June 30th and look ahead for the current year’s plans. Felt like the roller coaster ride, at times versus what the stock price chart looks like. But it ended up being quite a thrill.

Early in the new fiscal year, we announced the debt exchange, which put us in a better financial position a couple of months later to pursue the MitEnergy acquisition. Not only was that one of the most compelling acquisitions we’ve ever done but it also allowed us to significantly strengthen our balance sheet with equity due just accretive economics.

Once the deal was funded and closed, we were off for the races, just couple of weeks later in January we announced Davy Jones as a major discovery. Meanwhile our core operations have continued to deliver good results in a market warmed up to the story including the excellent reception we received at our first ever Investor Day in March in New York City.

And then BP rocked our world in April. We certainly had better summers than the one we’ve just went through with all the regulatory attention in the Macondo deepwater incident rocks our industry. But the bottom line is that the market greatly overreacted to the incident in relation to its impact on Energy XXI and other shallow water players.

Our production was not affected, our drilling program was not materially affected, our cost structure was not materially affected and we see no reason why any other will change going forward, from the shape that are stock were at until the market’s beginning to agree.

And now we believe once again we’re close to potential breakout to the upside. As you probably heard over the past couple of weeks, things are looking good at Blackbeard East, where we are drilling at 22,300 feet and are below the salt well. We have the potential to drill over 8,000 foot of interval within this trough and things continue to look very good there as we drill ahead, we’ve made basically 1,300 feet there over the last two and a half days.

So our drill rates continue to be outstanding at this depth and we’ll keep you posted as we drill. Not far behind Blackbeard East, we hope for the Davy Jones offset. I’ll talk about, that guys more in a couple of minutes.

Let’s switch gears now and look at the details around our year end reserve report and expectations for our capital program going forward. We ended the year at 75.6 million barrels, up 42% from the prior year. We produced nearly 8 million barrels last year and added about three times that amount with acquisitions.

Notably, despite a severely amended development budget as I’ll show you in a minute, our performance revisions, extensions and discoveries by themselves managed to offset about 60% of the produced barrels.

Looking at the reserve base in more detail, you can see even more impressive value equation. Our proved developed producing reserves rose dramatically year-over-year because of the Mit acquisition as well as the restoration of hurricane volumes. This had a big value impact.

The other key contributor to value growth was a higher percentage of oil reserves which rose from 58% to 63% through the Mit acquisition. Altogether, proved only reserve value rose almost 75% and that’s just the beginning of the story.

As an aimless recovery, we are required to report 3P reserves as shown on the slide 7. Remember that all our reserves were done by Netherland, Sewell & Associates on a third-party basis. For June 30 PV-10 for proved reserves is almost $1.9 billion, above and beyond that is nearly $700 million of probables and possibles.

All those figures are meaningfully higher if we use the current straw [ph]. Incremental to that our ultra-deep shelf interest which Netherland, Sewell estimate to total around 130 million barrels net to Energy XXI, combining only the Davy Jones and Blackbeard West discovers.

Let’s look at what is still needed before we begin booking those reserves. A potential timeline for Davy Jones, the key things as we drill ahead of Davy Jones we were at 15,125 as of this morning. We’re going to wait and squeeze a shoe there and then decide whether we’re going to set pipe here or drill ahead. The key thing about that logged well is we’ve got our straight hole going things are progressing the way we want.

We should be able to get wire line logs. We should be able to get the fluid samples. We should be able to obtain reservoir pressures and seeing a log like the one we’ve already drilled, we would expect to have cores within our reservoirs.

You put all that together and that should be all the data we need, based on our conversations with Netherland, Sewell to move these reserves from the contingent resource category into the proved category, at least on some potential space scenario of two wells or three wells locations at a time.

The other thing I think that’s important to keep in mind about the data we’re going to gain on all set well as is I’ve told many of you over the past six months, I think there is a one out of three chance that we actually probably can get 5,000 or 20,000 pound pressure equipment. That’s somewhat dependent on what sort of pressure aggression we see and how much condensate, this cast has with it.

The next slide kind of gives you the status update. We’ve talked verbally about it, but we want to ceiling plant. You can see where all the major items are from the safety valves through the trees, our tubing strings, our tieback casing and our kill systems and our perforating charges. Most of them are scheduled for the second quarter 2011 delivery.

Everything moving ahead smoothly, no hangouts towards making that completion and get this production sometime in October of 2011, which will be within 20 months of the time that we got off the initial discovery well.

We’ve covered many successes of fiscal 2010 I must look at the capital program and our expectations for 2011. One of the key things remember about our capital program for 2011 is we had the flexibility to design it around the Macondo incident. We knew what had happened. We knew about the increased scrutiny of regulatory permits etc.

So, our program is very much loaded with recompletions, workover, sidetracks and things that are easier to get approved in the how our new wells that required MTLO 6 [ph] which is where the majority of the hangouts been coming from.

Giving some sense, this slide here shows you our total CapEx $250 million. If you look at the next slide, you’ll see kind of year-on-year comparison between 2010 and 2011. I think the couple of key things that jump out at you on that slide is that we’re going from $25 million to a $130 million of development drilling.

Our exploration dollars are relatively constant and our P&As are down $78 million last year, down to $30 million this year and having to deal mainly with Eugene Island 330 hurricane abandonment that we were suffering through, last year and bearing the brunt of cost on.

So, we go to the next slide, you look at our growing production profile. We’ve felt mostly we expect to be in the 27,000 to 28,000 barrels for the year sort of number. To give you a little sense about where we are today, our capacity is running 26,000 barrels a day to 27,000 barrels a day somewhere in that neighborhood.

We’ve got over 4,000 barrels either ready to come or coming on within the next six weeks. That includes things like East Cameron 334 where we got two rigs completions we’re finishing up that will give us 1,000 barrels a day.

The two rig completions we are finishing up at Main Pass that are going to give us somewhere in the 2,500 barrel a day range. Then at South Timbalier 21, our (inaudible) well where we will TD later today, but we’ve seen enough of the log to feel very good that plays come in exactly as we expected it. That well will give us about 1,500 barrels a day once we have it completed.

In addition to that we got the Eugene Island 275 workover we did about a month ago. That wells been hanging in there pretty constantly at about 1,000 barrels a day. You can gather from that we feel very comfortable about our production going forward and we will continue to deliver on our promises to you there.

To wrap it up, fiscal 2010 certainly had its challenge given the economic conditions at the beginning and the deepwater tragedy at the end, but the Energy XXI had a phenomenal year.

The Group proved reserves 42% very economically. We then improved the quality of that reserve base by increasing the oil percentage and the crude producing percentage. We added to our shallow water ultra-deep shelf successes in advance towards first production and we achieved all this, while significantly improving our balance sheet.

Looking to our current fiscal year, we have a lot of exciting things on our plate again and our capital program is to deliver a lot of additional value from our core producing properties, while remaining within cash flow. It’s been exciting five years for Energy XXI and we firmly believe we’re on the cusp something even bigger.

Now let’s open up the lines for questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) And our first question comes from the line of Steve Berman with Pritchard Capital.

Steve Berman – Pritchard Capital

Good morning, everyone. John, a question for you first. With McMoRan I believe the expectations that I hope at least we’re going to have a permit for Lafitte in two weeks to three weeks, which was two weeks ago. Can you kind of bring us up to date on your thinking there for getting that permit?

John Schiller

Steve based on the conversations yesterday with McMoRan. That permit has actually advanced to the regional office. They’re calling up on it today. It looks like they’re going to be through with the EXL rig, sometime this weekend. So we’re probably ready to start sometime middle next week. So, we’ve got about another week on that permit before the rig goes on standby. The BOE knows that so I think things seem to be advancing at a pretty good pace.

Steve Berman – Pritchard Capital

However, maybe a question for West. You have actually a tax benefit and income tax benefit for the fourth quarter. Can you explain that a little bit and what are your expectations on the tax rate going forward in this fiscal year?

David Griffin

Our tax provision is a little bit complicated but the primary driver of why we are showing the tax benefit was due to the positive change in our hedge flow. As you know we do hedge accounting and we keep all of the gains or losses associated with our hedges and other comprehensive income or OCI which is part of owner’s equity. Until such time as we actually realize on that and settle the hedges. Because we are not a tax payer, the net effect of a gain in the hedge book is we actually have a positive tax benefit.

Walking through the details of it you’ve got, if you have $100 increase in the March market value, your hedge book, typically you would expect to see an increase in OCI of $65 and if you’re a full tax payer 35% or $35 increase in deferred taxes.

We are not a tax payer, we have a fairly significant net operating loss and so as a consequence in order to make the books balance the other entry that you make is actually a contrary entry to tax as we’re positive tax entry. So how that’s going to change going forward is it really depends upon what happens to our hedge book for the most part. There are a couple of other smaller items that do impact that number, but that is the major one that is a change in our mark-to-market values.

Steve Berman – Pritchard Capital

All right, thanks. I’ll let somebody else to go. Thanks, guys.

Operator

And our next question comes from the line of Duane Grubert with Susquehanna.

Duane Grubert – Susquehanna

Hey, guys. You talked about being prepared for permitting uncertainty, so you have a whole bunch of workovers and recompletions and so forth. Can you also talk about, have you guys thought of any onshore or near-shore opportunities as a result of being concerned about permitting?

John Schiller

We look that Duane but the reality is this, our whole program that we talked about, the $250 million development program requires us to get one MTLO-6 permit at South Pass 49, and we’re currently looking at the potential to sidetrack there and we may not even need that permit. If oil prices stayed high and we want to drill a couple of more oil wells, we are seeking permits at Main Pass 61 for two more wells we want to drill there that we showed you during our investor conference.

From an operator standpoint those are the only three wells that meet the new MTLO-6 permitting. On a non-operated side, Lafitte is the key one. The work that Apache is doing which I think even mentioned, they drilled a very good well for us at Eugene Island 330, the first well came in very good. They’re now going two slot recoveries there so that they can do the next two wells, and then we’ll complete all three wells once we drill them. None of that work requires MTLO-6. So it’s really not this overwhelming need to go look for places to drill to spend our money now.

That said, we are going to drill uplift well at Laphroaig, the Peterson well that McMoRan will operate and we’ll drill the Platte Exploration Prospect with McMoRan, both of which will be near-shore end of March not requiring any of the federal permitting process.

Duane Grubert – Susquehanna

So part of my read-through of your written release that you have recently gotten permits for workovers, recompletions and sidetrack. You’re telling me some of the drilling activity that’s actually a different operator. So I shouldn’t worry about that so much like it’s not committing for wells that need to be drilled.

John Schiller

Correct, I think although not quite following your logic.

Duane Grubert – Susquehanna

Yes. I think we should move on. One of the other things I wanted to ask you about was your comments on liquids and liquids expectations from the wells. In the prior core work and in the core work that you’re doing forward, how certain can you be about liquids content before you actually produce the well?

John Schiller

Well I mean if we give a lot of sample Duane, down the hole, we’ll be very certain about what kind of liquids we have with the gas condensate, NGLs, your density of your gas and your components of it. So what you’re really looking for with regards to a pressure determination as what’s your correct gravity. So you get a psi per foot sort of weight from your gas stream and your turbine and to give you some sense, dry gas is about a tenth of a psi per foot whereas oil is about 0.33, 0.35 psi per foot and water is obviously 0.465.

So the more liquids you have, the heavier weight of that column and less of that reservoir pressure you actually see at the surface. So the combination of how much liquids we might have in a gas coupled with an actual bottom-hole pressure because remember what we’re doing right now is kind of assuming a worst case. We’ve got the mud way.

We drilled the formation work as our pressure and dry gas and you do all that, we come up with 22,500 pounds as our shut-in tubing pressure maximum. So to move that down below 20,000 really doesn’t take a lot more than a pound per gallon drop in the bottom-hole pressure and little bit of liquids. Still with that data we have to design around what we know and that’s where we are at right now.

Duane Grubert – Susquehanna

Then clearly the other side of the conversation being the improvement to economics going forward. So in your running of economics, are you assuming any liquids or is that just going to be gravy, once you’ve run the economic?

John Schiller

Great point, Duane. When we look at things, at $4 gas we print money. If we run a 100% gas for no liquids, our breakevens about $2 a MMcf and you even start adding 20 barrels of million for the common side deal that’s $65 a barrel, then you end up driving our gas economic breakeven price below at $1 MMcf. So obviously, when you start talking about Tcf a gas (inaudible) adds up real quick in value.

Duane Grubert – Susquehanna

Very good. Thank you very much.

Operator

And our next question comes from Nicholas Pope with Dahlman Rose.

Nicholas Pope – Dahlman Rose

Good morning, guys. The exploration, I guess the exploration program, how much is being modeled in terms of success in the production gains or the production expectations do you all have for 2011 right now?

John Schiller

Zero.

Nicholas Pope – Dahlman Rose

I mean is that primarily just more of the development project, the recompletes, work over stuff, that’s going to bring up the production from the current rates that 27,000, 28,000 barrel equivalent a day?

John Schiller

Yes that’s correct. I mean the input from the exploration is minimum the cost of timing and things like that.

Nicholas Pope – Dahlman Rose

Then I guess for the fiscal fourth quarter, the $17.7 million of acquisition as listed is that mostly due the South Pass area acquisitions, is that the bulk of it?

John Schiller

That’s correct. We’ve picked up a couple of million barrels there.

Nicholas Pope – Dahlman Rose

What were those assets producing, the purchased assets from South Pass area?

John Schiller

Well, let me give it to answer in another way. In one quarter to offset that purchase price we got back about a third of the purchase price for the first quarter.

Nicholas Pope – Dahlman Rose

Then I guess with the Davy Jones, the schedule that you all put on here. Did it slip a little bit in terms of like when you are expecting to view to see production from Davy Jones or is that just I guess terminology with what we are collecting with the wells, it looks like it’s worth maybe a little maybe a month or two or is that just anything we should renew that?

John Schiller

Yes, I think you’re probably reading into too much detail on something that’s not nail down to the final day yet. There is always going to be a month move here and there on when banks are coming around. We’re showing the delivery dates based on what the guys told us at the time, there is a chance some of them with frankly lack of activity in the deepwater are going to move some of those projects ahead, some of them may fall behind, although I’d be surprised if we fall behind.

So I think the commitment that we expect late quarter calendar 2011 to have a test, that’s not going go away anytime soon. We’re in pretty good shape for that test. It could be a little bit earlier. But then, if we have a year like this with no hurricanes and maybe we’ll flow tested in September maybe we’ll wait till October because it’s all coming together around hurricane season. So, while we’re doing that a little bit of movement around there and they are dependent on what the weather looks like.

Nicholas Pope – Dahlman Rose

Then with Blackbeard East, it sounds like you’re making a lot of real good progress here recently. Any indications while you’re drilling with that last 1,300 feet or whatever that’s been drilled I guess of what the potential looks like anything further that you’re getting from way you’ve drilled through since we’ve last spoken?

John Schiller

Probably the final one thing I would say out of that is that it looks like based on plainly on all that we’ve seen in yesterday’s drills and that around 212 we actually popped out of our salt wells. So we go back to intercom when we talked about 19.4 19.5 coming through the top where things started changing. It looks like our original interpretation was even more corrective than we were given a credit and that all that area appears to be a well zone, an area where the salt was there at one time, got squeezed out and you had these shells collapsed together.

An easiest way to tell that is just how jumbled up the Paleo is and the fact that we took a 5 million, a year jump. So we’re still in minimizing sands. We’re still exactly where we want to be and now we’re drilling at pretty good cliff. We knocked out 600 feet each in the last two days and that’s still drilling at pretty good size hole. So all you do is stay with James Bob and stay tuned.

Nicholas Pope – Dahlman Rose

Great. Thanks a lot.

Operator

And our next question comes from Neal Dingmann with Wunderlich Securities.

Neal Dingmann – Wunderlich Securities

Good morning, guys. John, a couple of questions; first on M&A activity. Obviously there seems to be lot of passages out there, is there kind of an opportune level as far as the leverage side that you would like to stay at and you kind of how impressive would you look at, I don’t know plains or some of the other potential packages out there?

John Schiller

I thought we made it pretty clear, we would like to get our debt to capital somewhere below 50%. We are very comfortable with the debt level we carry right now because of our cash flow per barrel. But in a perfect world well we want to get it below 50% probably close to the 40%. Our key thing is, there are lots of opportunities out there; we are looking at a lot of opportunities. We don’t see any way that gas acquisition works for us because it can’t compete.

With the ultra-deep opportunity, we do think there is earlier deal that make sense to the extent we could find oil drill, it’s something we would look at very hard. But it’s also something whose timing would have to be such that we’ve seen the results from the ultra deep. Our shareholders have had a chance to see the impact of the ultra-deep before we did something that maybe we had to put some equity including the purchase to continue our acquiring portion of the business.

Neal Dingmann – Wunderlich Securities

Certainly would that include I guess, you’d look at even kind of Gulf Coast, or any at all that’s included in the packages?

John Schiller

You’re cutting and out a little bit Neal, hold on.

Neal Dingmann – Wunderlich Securities

If you look at Gulf Coast as well as, I mean you put (inaudible) projects something you see there?

John Schiller

It’s fair to say within our operating areas right now, we’d look very, we’d looked at everything. I know you want us just to look at West Texas or anything like that.

Neal Dingmann – Wunderlich Securities

Just two quick other questions on differentials. How you see those kind of going forward for the next couple of quarters?

John Schiller

The key thing on differentials, Neal, is remember like this, last month transferring back above WTI. When that happened, we tend to get almost a positive differential to WTI because the refineries down here in need to suite Louisiana crude we have and WTI is usually getting crushed, calls to what’s going on in cushion from coming from Dakota and Canada. So it really doesn’t affect the refineries down here, and that’s why from time-to-time you see some differential swings that don’t make sense. WTI really, when it gets crushed it doesn’t apply to us quite as much as (inaudible).

Neal Dingmann – Wunderlich Securities

Got it. And then last question if I could. As far as, I guess Jim Bob as far as, I know I think he was really announced this morning, a couple of there I think rigs that was going to be leaving, is growing up I guess rigs for some of the further deep plays when you start looking at that or is that something that you and Jim Bob are already talking about?

John Schiller

Well, I think that’s something we’re looking at. We are rolling and a good partner for drilling and we stay in pretty good contact with them. Jim Bob in particular stayed in contact with them. He knows everything is well on their fleet. We know what we want to do from a planted situation. We’ve been using the palmer here because it presented itself and gave us an opportunity to do some rig completions and 300 feet of water, that we couldn’t do were conventional jackup. So we’re not worried that we’ll not be able to drill our wells, just to put that away. I do think it’s sad for letting them leave the Gulf, but that’s something this administration has to deal with.

Neal Dingmann – Wunderlich Securities

Okay. Thank you.

Operator

And our next question comes from the line of Richard Tullis with Capital One South.

Richard Tullis – Capital One South

Hey, thank you, good morning. John, just looking at the CapEx guidance for 2011, excluding the $24 million, $25 million from the development budget related to Davy Jones, how much of the rest of that roughly $100 million is related to workovers and recompletes?

John Schiller

Of the $100 million? Workovers and recompletions are about $17 million to $20 million.

Richard Tullis – Capital One South

So essentially you’ll need to go through the permitting process for the, all the rest of those projects.

John Schiller

Richard no. I don’t know. Everything else is sidetrack, we only have one well in the entire 250 that requires a permit under NTL 06, after well at South Pass 49 and we are currently looking for way to sidetrack that well. It’s very key for you guys to understand for whatever, at the end of the day because of the way we do well designations in the Gulf of Mexico, if you drill out of an existing slot that’s previously been drilled that well is label to sidetrack, it is not subject to NTL 06.

They are looking for new Greenfield drilling exploration wells and new wells for instance at Main Pass 61, where we’ve never drilled out all our slots. There we have to go get the NTL 06. And it’s a subtle distinction, but to be honest with you, about 70% of the work that’s get done in the Gulf gets done without an NTL 06 requirement if you look back last couple of years.

Richard Tullis – Capital One South

Fiscal year ‘11 production guidance, 27,000 to 28,000 barrels a day?

John Schiller

Yes that’s correct.

Richard Tullis – Capital One South

Will the liquids percentage stay roughly the same as what you had in 4Q, about 68%.

John Schiller

Yes. It's probably going to be in that range, maybe as low as 65 to as high as 70. We bring on the Peterson wells towards the end of the year and that’s high rate gas well that may sway as back to gas a little bit. And most of what we are drilling is going to be oil wells, we’re going to actually increase the percentage.

Richard Tullis – Capital One South

How you see it flowing out for the year? I mean, if you can up maybe in the second quarter and flattening out from there?

John Schiller

Actually, I think we peak in third quarter of this fiscal year and kind of flatten a little bit from there going out at the end of the year.

Richard Tullis – Capital One South

On the insurance side what do you seeing there are anticipating?

John Schiller

I think we talked about it a lot. Basically, we are flat, premium, the premium at around $24 million to $25 million a year between last year and this year. On a per barrel basis that’s going to be down obviously because of a bid [ph] energy full year volume impact and the work we’re doing. Where you hear a lot of talk about this 50% is that, how do we go in the market, when we were getting ready to go to market, the indications were that number was going to be $18 million and where we’re going to get a 50% increase in our windstorm versus what we’ve had previously.

So we went from $18 million and $165 million of windstorm to $25 million and $107 million, $106 million of windstorm. So we kind of stayed even on our parameters, and it kind of have insurance guys work. They decide what number they’re going to get from you and then you negotiate what you’re going to get for that number. And so we got hurt, but year-on-year, we’re not really any different, and we’re just some where we all thought we were going to be.

David Griffin

Richard that insurance program we just put in place on June 30, so we’re already in.

Richard Tullis – Capital One South

And then finally, the OpEx on a BOE basis that we saw in the fourth quarter that looks like a pretty good run rate for this coming fiscal year?

John Schiller

Yes.

Richard Tullis – Capital One South

All right, that’s all I have. Thank you.

John Schiller

Thank you, Richard.

Operator

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

Joan Lappin – Gramercy Capital

Good morning, gentlemen. I hate the expression but can you give us more color on what Jim Bob was dancing on the ceiling about a couple of weeks ago, and what you’re also happy about as you’re drilling Blackbeard East?

John Schiller

I think the easiest thing at the end of day is, if you are a geologist, Jim Bob is a geologist, my geologists they are all dancing on the table because they got into the trap, they got into the porosity salt where they thought it was, it would come out from the bottom of the well now where we thought it was. As soon as you get into that the integral things change, I mean we literally Joan drilled 300 foot wet sand right on top of going in and there was no inkling of gas anywhere in the system. As soon as we start getting into this thing, you just start seeing hydrocarbons, so you start going pretty good. We saw six foot sand with really nice porosity and gas in it. So you sense that maybe your traps working.

So, now you got 8,000 foot to drill of hydrocarbon potential bearing sands over that integral and a trap that we think is going to work, that’s worked many times in deepwater. So, if you’re geologist you’ve done everything, you can do. You put us into there, you’re supposed to put us into and now it comes out through a little mother nature, you have those sands and whether they filled up or not.

Joan Lappin – Gramercy Capital

So as you’ve drilled this rapidly despite the large holes, have you seen anything else since you got under the salt?

John Schiller

As I’ve said we’re catching up with Paleo. We think we’ve popped through the well at about 21,250. So that means we’ve drilled about another 1,000 feet since to that, most of that in last 24 to 30 hours. Our LWD is working. So, if and when we see something that’s material, I’m sure we’re going to let you know about it.

Joan Lappin – Gramercy Capital

As you look forward to the coming year, what do you think is your biggest challenge, is it getting around more government scrutiny, is it obtaining the rigs you need, is it the permitting, is it money, is it whatever? My last question is if Plains warrants out of the Gulf of Mexico which I think they have said, what do you have in the way of right to first refusal?

John Schiller

Looking for our fiscal year right now, we feel pretty good Joan. We don’t see a lot of obstacles out there. If I go at 18 months and we need to start drilling more of the newer type permits, then we’ll hope, we’ll figure out that issue and things will be coming out little smoother than they are. To-date, we’ve had four wells issued under MTLO-6.

But I truly think we’re going through a learning process and once we know what each one of the (inaudible) it expects for a drilling permit then we’ll be able to deliver that on a regular basis and I think the permit process will smooth out. It doesn’t impact us this year. It could impact us next year, but I’m pretty comfortable, we’re going to have that worked out. Rigs are not going to be an issue; supplies are not going to be an issue. So we are feeling pretty good on all of those things.

With regards to PXP, basically it’s pretty tight and dry. If Jim sells everything that he has in the Gulf of Mexico there are no prep rights, if he breaks it into pieces, then perforates start getting figured on the different pieces.

Joan Lappin – Gramercy Capital

Okay, thank you. Keep up the good work.

John Schiller

Thank you.

Operator

Our next question comes from the line of Jeff Hayden with Rodman & Renshaw.

Jeff Hayden – Rodman & Renshaw

Good morning, guys. Most of my questions have been answered. I was just wondering, John, assuming success at Blackbeard East, what are kind of the next steps you guys would be able to as far as the Blackbeard Prospect area goes?

John Schiller

Well, I think it depends on what you see, I mean hopefully, we have tied above 26,000 feet. That’s the case, I feel pretty comfortable telling you that we can complete the 20,000 pound equipment and I think on one part to start moving forward with that completion that would have a decent probability of actually coming on productions, in front of Davy Jones 1. I think depending on what we see and how we see it, it would be a strong likelihood that we would do very similar to what we did at Davy Jones. We would slide the rig and drill a second well on probably the southern half of the structure.

So you got to see what all we have there. There is other comparing to what we see it, it may tell something about going back towards Blackbeard West. It might tell us about going to Captain Morgan [ph]. So our options are kind of up in the air right now, but the most likely scenario in my mind would be an all-set well and moving into completion mode on the first well.

Jeff Hayden – Rodman & Renshaw

Okay. And if you kind of move forward and drill an offset well, will that bump something else in the CapEx budget or do you likely take the CapEx budget up?

John Schiller

That’s a good point, Jeff. We’ve got about $40 million to $50 million of excess cash flow versus our cash needs right now. If we were to pick up and drill two more wells that we don’t currently have in the plan with Jim Bob that’s $15 million or $20 million order commitment wouldn’t probably all even get spent this year. So, I mean I think we would feel very comfortable on success and have like to continue to live within cash flow but spend the money on those wells without necessary bumping anything out of our development budget.

Jeff Hayden – Rodman & Renshaw

Okay. Appreciate it, guys.

Operator

And our next question comes from Phil Dodge with Tuohy Brothers.

Phil Dodge – Tuohy Brothers

I want to ask you little bit more about the $10 million in the budget for land and G&G [ph] whether any of that would be aimed at filling in windows in your deep shale prospects or would you be opportunistic about it and may be add to the $10 million if those chances came along?

John Schiller

Yes, I would say that right now we feel pretty good that on the prospects we like that are i.e. close to State of Mississippi where our large identifier prospects. We picked up most of the acreage if not all that’s available and open and now something popped up and someone let some acreage go surely we go after that but that those dollars are more geared towards seismic for the most part filling in some things around our Laphroaig well, filling in some place within our Main Pass area things like that reprocessing of data like we’ve been doing in South Timbalier.

Phil Dodge – Tuohy Brothers

Okay. So there is nothing for that in the $9 million to $10 million next year. And then another question you are rolling, moving the Coffman rig out of the Gulf, what would you and McMoRan follow up with on that in terms of rig availability.

John Schiller

What you got to remember is that we got two more EXL’s coming out one this year one scheduled for early next year, but I know that there is a conversation that with a little bit help for most dollar wise, it can probably move that into December this year. So you got two more rigs like the rig we are getting ready to use in the feet, which are a little bit cheaper on a day rate and specifically really designed for these wells.

So again, we’re not in any sort of panic mode over access to rig to drill with. We continue to look at other opportunities, where we can use particularly in the Davy Jones area and England as we move closer to shore the potential for using a barge rig or submersible rig that’s rigged up to handle this kind of casing wells.

Phil Dodge – Tuohy Brothers

Okay. Thanks very much, John.

John Schiller

Thank you.

Operator

Our next question comes from the line of Don Chris [ph] with Johnson Rice.

Don Chris – Johnson Rice

Good morning, guys. Actually I had one, I have the conference and then here for a second, but I’ll just pass for right now and get back in queue.

John Schiller

All right. (inaudible).

Operator

Our next question comes from Richard Redmayne with Seymour Pierce.

Alan Sinclair – Seymour Pierce

Hi, gentlemen. It’s Alan Sinclair here. But a big team from Seymour Pierce from London. How are you doing?

John Schiller

Good morning.

Alan Sinclair – Seymour Pierce

Can you give us, in terms of the exploration targets you’ve got on Main Pass and South Tim, you mentioned more do on South of Tim, but can you run us through, if possible the drilling schedule for the other targets? I mean Cohiba passed and then excuse my pronunciation Camacho [ph] and I’ve got Crete and Khios in addition to Bordeaux. Can you outline what the plans are there, because Crete…

John Schiller

Sure no problem. You’re actually referring to some of the stuff we showed at Investor Day. Ashton and Onyx are both going to be sidetracks out of Main Pass 73. They are in the budget. It’s looking like October, November despite those wells. Crete, we continue to move forward on the reprocessing of the seismic data and that’s it’s turned out to be even more complicated than we thought. We knew that the Terrebonne trough kind of runs through the middle of our South Timbalier 21 Field and what that means is that at 20,000 acres we have there, 10,000 for the east has totally different velocities than the 10,000 to the west, so we are slowly moving through that.

We still expect the delivery of that reprocess seismic this year and it probably be first quarter of next calendar year before we are in a position to spud that well. And that leads us with Cohiba, which is probably one that’s I don’t know that we’re going take two big shots like that this fiscal year. And important thing to remember is all that held by productions. So it’s not going anywhere on us.

Alan Sinclair – Seymour Pierce

Okay. Thanks, gentlemen. Makes sense. Thank you.

Operator

And next we have a follow-up from Don Chris.

Don Chris – Johnson Rice

Yes. I cut off earlier in the call. Just had a couple of questions on timing at both Blackbeard East and Davy Jones with Blackbeard East, it sounds like your real progress is going very well. What’s the expectation if you move down to a solid pipe or smallest range and you expect that to go down or to 3,000 feet is going in fact (inaudible) a day, you could be there pretty quick?

John Schiller

That’s the nature of drilling. So, predicting that we’re going to stay at that rate is a tough thing to do. Well, I will tell you on Blackbeard East, we feel pretty comfortable about well TDs this year, calendar year. Just to remind you there was a 0.5 in there where we made three bit drips and didn’t make 10 feet a day, and then all of a sudden with the same bit that hadn’t drilled for a day we popped and made 400 feet. So you never know what’s ahead of you in the drilling world, but yes, we’re making good headway there. We see no reason that wells might have PD, here over the next two to three months.

On the flip side at Davy Jones, we’re at 50 to 1. We made 3,125 pretty quickly there too. I think that was one bit or two bit? Just one bit run, so I mean we’re making good hole there. We continue there to fight circulation issues and loss returns, and that’s why we’re at right now. Again ready to squeeze our shoe and see that’s where we’re losing fluid, and then make a decision on second pipe or not. I think that well, we should definitely be in the target sands before the end of the year. Whether we’re actually physically to 30,000 foot end or drill through the Tuscaloosa by the end of the year, I’m not sure right now.

If you’ve listened when we talked the last month, what we thought would occur is that we lost some time on the big hole portion of these two wells, but now as we’re getting deeper like at Blackbeard East, you’re seeing that we’re drilling a nine or eight to about 11 and 11 a quarter undergoing total and we’re still making 600 foot a day. That blows away any sort of rates we saw at those gaps in the wells where we entered in that smaller bids. So the big bids down hole are starting to deliver the results we thought they would.

Don Chris – Johnson Rice

In terms of optimizing the values as hydrocarbon shales at Blackbeard East were those extracted pre-drills, it sounds like your seismic has been right on and I guess the follow-on to that is on the Davy Jones you also talked about not only being uptick, but also having some shallower sands in fact that you may encounter and what’s the point, are you guys below the salt end of it that you start to get into those shallower sands?

John Schiller

Probably the best way to describe the seismic is maybe even the engineer calls the black magic science, but anyway when you look at the seismic, what the guys were picking up early on was that you had it very supportive the lack of a better word of smear zone and that smear zone was roughly 2,000 feet, and now it looks like that’s what we just finished getting through and now ahead of us and coming right up in front of us where we actually see what we call reflectors where you can see things on the seismic that you can map over large areas. Reflectors tend to be faint it doesn’t mean they have to be.

That mean they will be in this case, but that’s what one tends to see a reflector tends to be something with some porosity and permeability that’s impacting your seismic wave a little bit different than the shales and the other rocks. So, those are what we always saw, that’s always been at 5,000 foot interval we talked about that we never saw on Blackbeard West, and all of that is sitting right up in front of us right now.

Don Chris – Johnson Rice

You mentioned earlier, you expect to have kind of $50 million or $60 million or $40 million or $50 million of excess cash flows above the $250 million CapEx is that based on your production guidance of 27,000 to 28,000 a day at particular price that we’re or how should we think about that comment and million dollars of cash flow.

John Schiller

Actually what we are doing is taking our capital and our cash cost that we know exactly what they are going to be and we are taken it off of a consensus EBITDA estimate from the street.

Don Chris – Johnson Rice

And I thought the consensus is little bit higher than that in fiscal ‘11.

John Schiller

Well that was my nice way of telling, our number might be higher than that but we are just being consistent.

Don Chris – Johnson Rice

And then lastly just on the production build, is the expectation since you have some wells ready to be hooked up, I would assume that you expect some sequential increases both in the first, second and third quarters before you start that at this point you’d expect that will have complete obviously depending on maybe price?

John Schiller

I think you asked earlier but I think if you look quarter-by-quarter we probably peak in the third quarter of this fiscal year, kind of ramp up the next couple of quarters over there and then the fourth quarter of our year kind of hold flat to maybe down, we’ll see where the where the budget and the programs are at that time.

Don Chris – Johnson Rice

The fourth quarter in terms of depending on Davy Jones, fourth quarter is June that would be fiscal ‘12?

John Schiller

Correct.

Operator

I would like to turn it over to our speakers for any closing remarks.

John Schiller

Alright everybody thanks for all your questions. We appreciate your support. A good year, another year ahead of us and we’re looking forward to you and we’ll keep you guys posted as we know more and more. Thanks.

Operator

Ladies and gentlemen, thank you for your participation in today’s conference. This concludes the program. You may all disconnect. Everyone have a great day.

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