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Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

F1Q2011 Earnings Call Transcript

October 26, 2010 9:00 am ET

Executives

Stewart Lawrence – VP, IR and Communications

John Schiller – Chairman and CEO

David West Griffin – CFO

Analysts

Dan Chandra – DW Investment Management

Duane Grubert – Susquehanna Capital

Eric Anderson – Hartford Financial

Don Crist – Johnson Rice

Phil Dodge – Tuohy Brothers

Adam Duarte – Omega

Steve Berman – Pritchard Capital

Richard Tullis – Capital One South

Nicholas Pope – Dahlman Rose

Joan Lappin – Gramercy Capital

Jeff Hayden – Rodman & Renshaw

Jason Wangler – Wunderlich

Operator

Good day, ladies and gentlemen, and welcome to your Energy XXI first quarter 2011 earnings conference call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will be given at that time. (Operator instructions) And as a reminder, this conference is being recorded. I would now like to introduce Mr. Stewart Lawrence, Vice President of Investor Relations and Communications. Please go ahead.

Stewart Lawrence

Thank you, Mary. Welcome to the call today, everybody. Presenting today, we have John Schiller, Chairman and Chief Executive Officer, and West Griffin, Chief Financial Officer. We also have the management team on the line for additional questions at the end of this. We will be available, of course, at the end of the call to address all those questions.

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 releases 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, 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 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. Thanks for joining us. Our year-end call was just a short time ago. So we’re going to keep the formal remarks brief today and leave time for Q&A at the end of the session. I’ll note that since we started our fiscal year on July 1st, we successfully launched our capital program.

Our current production capacity exceeds 28,000 barrels a day although, as we always guide you, not all of that will flow on an average day, particularly when we are running an active June program, which sometimes requires us to shut in facilities. But we’ve had some recent run rates of approximately 27,000 barrels a day, and I expect that to continue to rise. To date, all of this year’s capital projects have come in at or below the peak cost and within the scheduled timeframe. So clearly we have no problem to executing our program despite what you may have heard about the Gulf of Mexico operators.

A little detail around the program. We’ve drilled three successful wells. The Eugene Island 330 where Apache operates, we’re starting completion on the first well there. And we have six to eight wells left in that redevelopment program, but just to give you a sense of how it’s going on a gross basis, this is a field that we own about a third working interest in.

We had about 3 million barrels of proved reserves. Our first three wells have delivered on those proved reserves. So everything we drill from here, we will be generating that. So we have been particularly happy with the redevelopment of that old build that we picked up interest in both the Pogo and the Mitsui deal with.

At South Timbalier 21, we are drilling at 7,935 on our Shiraw [ph] prospect on our way to the 11,619 feet measured depth. Our Berola Twin [ph] is now producing in excess of 2,500 barrels of oil equivalent per day gross. 90% of that is oil from drill completion.

At McMoRan, at the McMoRan-operated Valentine Pontiff well, which is the up-dip well to our Peterson well on the Laphroaig discovery. We are already drilling 14,945 feet there. Come up on another chasing point on the way to planned PD of 20,000. McMoRan has done a great job there with approximately a month ahead of schedule already on that drilling.

Continuing in addition to our operational success, it might get progress on the financial side. Over the last couple of weeks, we’ve completed several changes for 38% of our preferred shares. And then last Thursday, we launched a tender for the remainder. Those shares are already in our diluted count. So the net effect of these changes is the fact $19 to eliminate about $30 of dividend requirement for $100 fixed amount, through the first call day more than four years from now. It works up more than 20% rate of return for our shareholders.

In addition, we’ve monetized all of our natural gas hedges netting $47 million of cash. That’s a good indicator where we believe we are in the natural gas price cycle. It’s not that we are super bullish on gas, we just don’t see prices going much lower than this. The dry gas rig count is starting to shut down and production from the Gulf of Mexico into the de facto moratorium continued to drop.

86% of our pre-hedged revenues come from our oil production. This allows us the luxury to go and make this better, and re-hedge the gas down the road as the strip price rises. With new volumes coming on, we continued to actively manage our oil hedge position. The update of the hedge schedule has been posted on our website. You will see that our focus has been on protecting the downside while leaving upside potential, remain bullish on oil, but we want to protect our cash flows.

In summary, our hedge position is 65% of our revenues for fiscal 2011 hedged and 38% of our revenues through December 2012 hedged. Our bullishness is looking very hard at all focused acquisitions. As you’ve heard me say it many times, while we are not that interested in pursuing gas opportunities, we would look very diligently at anything that’s oily in nature.

Nothing is currently captured, but we’re looking at multiple opportunities. Any acquisition we do would be expected to add value for our shareholders and to further strengthen our balance sheet in the process. Of course, an addition to actively pursuing our (inaudible), we are continuing to pursue our shallow water ultra-deep shelf exploration drilling.

In September, we’ve found all naysayers and received the permit for our Lafitte well as well. That well was spud in early October, and as of this morning, it’s preparing to drill a lot of case in that 4,665 feet. At Davy Jones, we’ve got a liner set out 20,000 feet preparing to drill out.

A couple of things of note on Davy Jones. We are 2.5 miles away from our offset well and that these wells are drilled totally different. High core pressures, large amounts of gas involved in this drilling, and some things that we take in line with the exploration from what we see is very encouraging. We’re currently right at the salt weld. We’ll get through the salt weld and then the fund is going to start very shortly thereafter, as we start looking for casing into below the salt weld.

At Blackbeard East, we have done – one of the things that I won’t think those relate good enough for you guys were we ramp-up liner and our tiebacks. So we ran a liner down the 26,000 feet and then we tied our tieback casing string all the way to the surface. Three separate segment jobs. We have drilled all that out. We have tested our casing as of this morning.

We’re preparing to go out and drill out the shoe at 26,000 feet. Assuming we have a good segment job there, we will be going back to drill. The thing that I think people would miss from this, we have both the potential shallow Upper Miocene gas discovered and a deeper Lower Miocene gas discovered, both of which are going to be developed utilizing conventional 20,000 PSI equipment.

Another significant point of what we’ve got to date so far is that we found to see the Miocene sands above 26,000 feet and below the salt weld. And this is a huge potential for all of our plays, particularly the southern portion of our play that includes Lafitte and Captain Blood where we now think based on everything we are seeing that we may see as much as 10,000 feet of Miocene intervals available to us below the salt weld.

I caution everybody to remember when we first found this well, if you yield back to my Howard Weil presentation, I spoke then about (inaudible) rewriting the geology books and how this works. I told you then that we were bringing the insight. We entered in the (inaudible) because you are actually watching a major trend being developed in real-time as a part of the material impact on our two companies. That generates data and you get what you want. In some days, you hear some things, you don’t quite understand.

What I’m talking about how you can’t be more upbeat than we are. We’re going back to drilling. We’ve got a lot of sands drill in front of us. The sizes we’ve already put behind type. And the entire ultra-deep shelf program continues to open up one well at a time as we go below the salt weld and learn more and more about it.

I’m certain we have plenty of questions on these projects that we can address in Q&A. But first, let’s turn it over to West to review the financials.

David West Griffin

Thanks, John. The quarter’s results generally speak to themselves. But let’s take a look at a few of the line items. Energy XXI generated approximately $76 million of EBITDA during the fiscal first quarter, which equates to almost $32 a barrel. Operationally, our daily production volumes grows nicely on a sequential basis and significantly year-over-year, with oil continuing to represent a higher portion of the volumes, reaching 69% last quarter.

As John mentioned, production has continued rising due to the success of our drilling program, putting this on track to average 27,000 to 28,000 barrels a day on a full year basis. Cash flow in the first quarter benefited from a higher crude oil mix, but also because of $34 million of cash from our gas hedge monetizations. We will record another $13 million of proceeds in the current quarter, bringing the total to $47 million.

Looking at lease operating costs, despite all the hand wringing, our new insurance package has cut our costs significantly on a yearly basis. That was partially offset last quarter by work-over expense due to the work that we’ve been performing at Main Pass 61 and East Cam 334.

G&A was the biggest item of note. As we’ve spent approximately $7 million on a one-time non-recurring basis associated with severance payments to sea water [ph]. In addition, stock-based compensation expense was $4.5 million, partially reflecting an increase in the stock price of approximately 46% from $15.78 at the beginning of the quarter to $23.11 at the end of the quarter.

With that, I’ll turn it back to John for closing.

John Schiller

Thanks, West. As I stated, we’ve been really excited with the quarter’s solid numbers. I’ll tell you that on an internal estimate, we are about 1,400 barrels a day ahead of where we expected to be for this quarter. So we’re feeling very good about the 27,000 to 28,000 projection. I was getting another quarter on our belt, get through some things we got to get through this quarter, and then we’ll be looking hopefully to give you an even better number there.

So with that, let’s turn it over to operator to some Q&A.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) Our first question comes from Derrick Jumper [ph] from DW Investment Management.

Dan Chandra – DW Investment Management

It’s actually Dan Chandra. Congratulations on a great quarter.

John Schiller

Thanks.

Dan Chandra – DW Investment Management

I have two questions. First, on Davy Jones 2, can you give us a sense on when we should be looking for more concrete results or any announcements on that? And the second is, on Blackbeard East, on McMoRan’s conference call, there seem to be a lot of confusion, a lot of question marks surrounding the well that’s been drilled so far, especially in relation to the possibility of water in the reservoir. Can you talk about that and kind of clarify what you are thinking in terms of that well? Is it possible it’s just a dry well?

John Schiller

Sure. On Davy Jones time, I would say that we’ve specified we’ll drill the next two or three days probably. We’re either going to be going through the salt weld and setting tight string again or we’re actually right there and maybe we can drill without certain string. But depending on how quick this has been drilled, the main interval that we want to get to is probably toward 25 to 25.5 is where we see the tops (inaudible). If you remember (inaudible) that gave us some indications in the original well that it might have pay potential, particularly we got up here and then had about 26.0 to 26.5 is where we start finding the pay sands that are (inaudible) we talk about in the original Davy Jones discovery.

To put that in perspective, we’ve been drilling 300 to 400 feet a day even though we were fighting the gas. So if our penetration rate stays up, we can start making a lot of hole here, very similar to what we did at Blackbeard East. If you remember, as soon as we went below the salt weld at Blackbeard East around 19,000, we got down to 26,000 pretty quickly with some really good drill day. And right now, we think we should be able to something similar to that. Second, at Blackbeard East shore, I mean, we’ve gathered more data. We’ve got sidewall cores, we still don’t have the SCM work, which will tell us a little bit about what’s in the sand itself in terms of minerals. We have various interpretations of what the IDMs are telling us from pressure. And that’s what I alluded to.

We have two sands, the Upper Miocene interval right on and into salt weld, and then one interval deeper in a well that we think about discoveries. We’re mapping it, we’re looking at our seismic drill time, how big they are and what are they potentially representing. Yes, we have a water lobe in one of those sands. That’s what we do. I mean, we find gas and we find water. So the fact that we have water has absolutely nothing to do with what the future sands are going to have. We’ve got multiple logs on multiple large discoveries where you typically see gas, water, gas, water, sort of trapping mechanisms. I think we might have misled people, and I appreciate your question, and that you got to remember there are two types of trends going on here. There is the Wilcox-Davy Jones-type play where in general we’re drilling a big four ways. And that is the one environment where you might expect to find what we found at Davy Jones where we have 1,700-foot of vertical hydrocarbon columns worth of sand. Every sand we saw in there is for the base. A four-way like that is a kind of trap that makes all the sands fill up.

When you are drilling a salt well, when you are drilling a three-way closure, when you’re drilling a fault, depending on when that migration was occurring and what was just the position to cause the trap, you can have some zones that never trap and some zones that do. And that’s very common in our business. So the key thing is we’ve got regular quality lock with good porosities, good capabilities. We have hydrocarbon. We have gas. We have a lot of sands left to see. If you look at the cartoons that we are showing to, what we’re trying to tell you is we think based on Blackbeard West that we were missing a lot of section in the Lower Miocene. We’re missing that section because of our fault or non-conformally will show up – come up with different interpretation. But based on the Paleo data, we’ve got a lot of sand to see in this well that we’ve yet to see at Blackbeard West.

Dan Chandra – DW Investment Management

Great. And then in terms of your capital structure, obviously you’ve done a great job by addressing the trap now. But it seems to me that the rest of the capital structure is a bit expensive. You guys are doing – putting up great numbers quarter-after-quarter. Can you talk about any thoughts about addressing that capital structure in the near-term, potentially with the refund?

John Schiller

Yes. I mean, I will tell you that we’ve looked at everything out there from doing optimum sold, next July when the 16s are callable to refinancing, to equity raises and everything in between. (inaudible) What I will feel very comfortable telling you is that debt won’t be out. There comes a lot next year when it’s callable. And we’ll see what to do something before that.

Dan Chandra – DW Investment Management

Great. Thanks very much and congratulations again.

Operator

Our next question comes from Duane Grubert from Susquehanna Capital.

Duane Grubert – Susquehanna Capital

Yes. John, the debate over the sands that you’ve already encountered at Blackbeard West, you just mentioned you are working to quantify volumes in the individual sands. I guess the question that I feel the lot – maybe you can just buoyantly hit it on, both McMoRan and you guys have stayed away from calling it pay. What would have to happen to make you call those sands that have good porosity, good permeability hydrocarbon? What’s keeping you from calling it pay?

John Schiller

Good morning, Duane. First you said Blackbeard West. So I –

Duane Grubert – Susquehanna Capital

Yes, I meant Blackbeard East, sorry.

John Schiller

Okay. Yes. I don’t know that there is anything about calling pay. I mean, if you ask us, we’ll say as pay. I think there is some hesitation right now with sharing a lot of data specifically on some of these sands from a competitive nature. I would tell you that from a reserve standpoint, we think we have all the data we need to call this pay. What we are going to do is trying to figure out how big it is. It’s clearly something that is a different development phase versus what we’re going after. These are shallower sands, 20,000-pound of conventional equipment. And so it’s a little bit different animal world. We come back and do some work and test our theories on where we think the reservoirs are there as we’re mapping them versus what we’re chasing in the rest of the world. So I don’t have any hidden treasures on that paying that well at all. I still think there are a lot of interpretations as to where we drill the next well to prove it up.

Duane Grubert – Susquehanna Capital

Yes. That’s very helpful. And I’m sure lot of people appreciated that. Totally different topic, on Davy Jones, the development plan, which you guys have as a group submitted to the regulators, can you talk us through what’s in the development plan? And is there any infrastructure long lead item that you are already thinking about?

John Schiller

I’m not the right guy. We talk about every detail on the development plan with the government. But the long lead item, we’re well on track for everything we’re building there from the 25,000-pound trees to 30,000-pound BOPs to electric line works and perforating charges, everything else is on track to complete the first well. We are also moving forward with central facilities that will allow us to produce to our own facilities as a partnership. And long-term, those are outstanding economics versus paying someone else to do the processes. I don’t know that we have a formal decision on where – all three on whether we’re going to go to the first well into our own facilities or in the Chevron. How is that?

Duane Grubert – Susquehanna Capital

Yes, that’s great. I think it just articulates that you are confident enough that you are talking about facilities already. And the third thing I want to be hit on was, you’ve mentioned in the past that the shallow water ultra-deep play conceptually moved onshore to the non-deep. Is there any work going on internally at either Energy XXI or within the partnership to look for coastal or a non-shore version of the ultra-deep program?

John Schiller

Yes. I mean, I can’t necessarily speak for everybody else in the partnership, but I think we are all doing the same thing. We are looking at our existing acreage within the Gulf of Mexico. We’re looking at our existing acreage on the Gulf Coast, and we’re looking at potential opportunities out there in the Gulf Coast. So it’s like any other big trend. It’s opened up. I’m not going to go to all the people that are talking about drilling. It looks like wells and all that, but people are starting to drill wells. All of those pieces a day that will be to a certain degree more information. We just have the most ability to buy it currently. So yes, we are stretching our advantage where we can.

Duane Grubert – Susquehanna Capital

Great. Thank you very much.

John Schiller

Thank you, Duane.

Operator

Our next question comes from Eric Anderson from Hartford Financial.

Eric Anderson – Hartford Financial

Yes, good morning. John, I wonder if you could talk briefly about the gas that you folks found on the way down Davy Jones 2. I believe starting around the 15,000-foot mark that for quite a while to get through. I’m wondering sort of out loud that this process might be another flat rock type field that you and your partners could develop independently of the deeper prospects of Davy Jones.

John Schiller

Eric, thanks for that. That’s clearly a possibility. I mean, the thing you have to remember is while we’ve talked about the nice, big 20,000-acre structure at the Wilcox level, when we get down to 26,000 feet, the reality is 2.5 miles away in the shallower Gulf, there is a huge (inaudible) for most of the geology that’s occurring a problem. So yes, we are seeing totally different things. We’ve logged the well. We don’t see big boom in the obvious casings. But something has given us all this gas. And one of the theories is what you’ve just alluded to, that we’re certain on the edge and channel-type trap like (inaudible) expiration standpoint from the fact that you guys are under-deserved because we kind of tell you everything we know as we know it. There is some opportunity there to come back with a future well. We’re looking at the seismic hard, trying to see which way to go and get some sense of why the wells are drilled totally different.

Eric Anderson – Hartford Financial

Okay. Fair enough. Thank you.

Operator

Our next question comes from Don Crist from Johnson Rice.

Don Crist – Johnson Rice

Hey, guys.

John Schiller

Good morning.

Don Crist – Johnson Rice

I was asking a little bit about – John, I may have missed the comments. You said about getting assets at the Davy Jones offset, Is that coming from some of the showers owned above the salt? Is that the right way to rig into that?

John Schiller

Yes, exactly. I mean, this is right back up shallow of low 15,000 feet and above 20,000 where there is all those saying in the last call – question, geology can chance a whole lot in the Gulf of Mexico for 2.5 miles at those depths, totally different depositional environment and what we’re going after at the Wilcox level where all that stuff was light down, pre-structured or consistent structures, are continuously structure being formed. So on top, we’ve got a lot of different banks, 2.5 miles away is a world of difference at 15,000 feet in the Gulf of Mexico. So something happened there. We’ve got some ideas, which we’re going to continue to look at it. And then it’s probably another well to drill in there and see we’re wide on what we think we’re seeing.

Don Crist – Johnson Rice

Okay, great. And then, as you move forward in drilling that well, once you get below the salt weld, I think in earlier comment you made is starting around 25.0 to 25.5. Is that when you hope to start to see the sands that two or three sand packages that you didn’t see in the original Davy Jones well that you thought you may pick up in this one before you get into the main Davy Jones sands?

John Schiller

Actually, not that we didn’t see them, but we saw – we saw it was part of sand and we sand. And we can get have some potential when we go 500 feet or 1,000 feet up dip. Okay? So I mean, think about it. We’re 1,000 feet up-dip and you’ve got a 100-foot sand and you can put a lot of gas in there. So we saw some things there that make us think it might have some high ended up. And then in the other sands, the real eight sands that we saw down dip should start somewhere around 26, 26.5. And then once we go below, say, 28, we ought to start looking for new sands that we haven’t seen in the previous well.

Don Crist – Johnson Rice

Okay. And I know both McMoRan and yourself have mentioned because of the pressures that you are seeing at Blackbeard East, maybe the opportunity for – to produce at least some of those sands with conventional equipment, I was asked a couple times at their call as to whether or not they alluded to – all being able to produce all of BlackBeard East with conventional equipment. Can you just walk through what needs to occur? What you are seeing in that will allow the more conventional 20,000-pound trees to produce the Blackbeard East?

John Schiller

Yes. I mean, it’s all a fortune. (inaudible) pressure to see and what your gas liquid content is. So, on everything we’ve seen to date, we feel very comfortable with 20,000-pound development, The sands were getting ready to drill. Let’s hope we have a nice discovery there too. It would just kind of depend on what kind of pressures we record. The good news is that all of our long run went smooth as silk. We made two runs with triple combo, two runs with bankers RCI pressure tool, and a run with the sidewalk. We had the pressure done. I mean, the pressure tool in there for three and four hours in one spot getting our samples, and we had no issues. So that’s good news for log and even a deeper depth. As long as the results show, they are working like that and we can get the information, and then we’ll have to tell you that we have a couple sand, we can do at less than 20,000 or we’re drilling at 25. The thing I think you are going to realize over the next six months is drilling a 25 is doing 25 is not really a big deal. Everything they were doing for Davy Jones completion come together very well, on schedule. And once you spend the money to get to engineering and certification done, the incremental cost, whether it’s 20 to 25 is not a deal fill at all.

Don Crist – Johnson Rice

Okay. And is there some component of what you are seeing in terms of those pressures that has led to some of the (inaudible) that there may be some liquids, maybe not directly oil, but at least compensate as opposed to all gas in that well?

John Schiller

I’m not sure where all that is coming from. I will say that our current interpretation there is we have gas. Okay?

Don Crist – Johnson Rice

Okay. And then two short ones. On just the timing, Blackbeard East and Davy Jones offset and will peak. Are we still on track for kind of fourth quarter of this quarter, first quarter of next year, and late first quarter, second quarter next year in terms of timing for those three wells through accurate drilling, assuming drilling continues to progress with –

John Schiller

Yes. Not necessarily sure if I followed it. It just shows in clear Blackbeard East, I would think, will TD this year. Davy Jones, I think, will be in the (inaudible) this year, may not necessarily be a TD, but we should be in the upper portion that probably scans at a minimum. And then Lafitte gas is the second quarter next year sort of target.

Don Crist – Johnson Rice

Okay, great. And then one progress probably on the 70 analogy number, was most of that related to the severance payments or can you break down the severance payments versus the incremental performance take?

David West Griffin

Yes. It’s mentioned perhaps $7 million of the total G&A was a one-time event associated with severance. And then on the stock-based compensation, the total amount during that quarter was $4.5 million, and the reason why this $4.5 million versus a lower member if we had significant increase in the stock price, roughly 46% during the quarter. We pointed the end of the quarter. And on the stock price compensation yet, sort of two elements. You had a timed element associated with it and then the catch-up element. So, as defined element continues to occur, but the catch-up element to the extent your stock price goes up, that’s where it moves that number up. So on an ongoing basis to sort of, I think, get to our point, clearly we’re not going to have severance. That was a one-time we’re going to have. And then on the $4.5 million, probably another $1 million or so – $1.5 million or so is associated with sort of the rod on the stock price. So you’ve got a couple of different elements associated with that. So we are high about that $8 million.

Don Crist – Johnson Rice

Okay. But the $7 million is severance?

David West Griffin

$7 million in severance, which is non-recurring obviously.

Don Crist – Johnson Rice

Hopefully.

David West Griffin

(inaudible)

Don Crist – Johnson Rice

Okay. And –

David West Griffin

(inaudible) but that’s nice too.

Don Crist – Johnson Rice

Right. It's a good problem to have. Hey, then, West, when I look at your cash flow statement, when you have the stock-based compensation of $1.8 million added back into your cash flow statement, how do I reconcile that with the $4.5 million you just mentioned?

David West Griffin

Right. Okay. So, on the stock-based compensation, there are couple elements associated with it. There is the accrual that we incur every quarter. But we actually have – as stock-based compensation, we have RSUs or units and we actually generally pay those out of cash unless the employee would prefer to have stock. And we give them the option of what they would prefer. And so you actually have the non-cash portion of it, it is we add back in the cash flows there.

Don Crist – Johnson Rice

Okay, great. All right. I appreciate it, guys.

Operator

Our next question comes from Phil Dodge from Tuohy Brothers.

Phil Dodge – Tuohy Brothers

Good morning, everybody. Let me ask a question on the legacy property. Everybody else got into deep shale pretty nicely. What would you expect the difference, if any, to be in your proved reserves as of June 30th, '11, as a result or consequence of the delays in drilling permits? I suppose it could go either way because of that.

John Schiller

Yes. Well, remember, Phil, many things were focused on that part that we really do really well too. But we’ve got 20 drill wells to execute this year in our plan, about $250 million capital. Of those, $18 million that not need the NTL 06 requirements. So we’re going to get all those done. One of the ones that needed the NTL 06 is the Lafitte. We’ve got its fund. So at least one well out of South Pass 49, and we’re evaluating whether we actually need to drill in a new slot there. We can side track a well. But that is not going to occur until March of next year anyway. We’re going to be to execute our entire program.

As I mentioned earlier, for instance, Eugene Island 330, we’ve drilled three out of what scheduled to be eight wells this year and 11 total on that drilling program. And we’ve already matched all our proved reserves we have for the whole program. So – in terms of what’s on the book. So we’re going to get some nice adds there. Some of our key wells in the South Tim, the Creek Prospect, some of what we are doing at the Main Pass like Ashton where we are re-entering some of these old fields and drilling some up dip amplitudes in areas where we didn’t think there was existence of pay before. If all that works good, I think we would look to just on our core assets, say, at last even show some growth in reserves. And then the big swing comes from what happened with the ultra deep success.

Phil Dodge – Tuohy Brothers

One other one, let me ask you on Laphroaig. I like that name. Can you remind us of what the on-risk potential or any way you want to put it on, the well that you're drilling now?

John Schiller

What name did you say? I’m sorry.

Phil Dodge – Tuohy Brothers

Laphroaig.

John Schiller

Laphroaig, okay. Yes –

Phil Dodge – Tuohy Brothers

The Laphroaig Prospect.

John Schiller

Yes. Well, it’s actually drilled as a development well. Remember, we are drilling up dip to a well that we’ve already made 30 Bcf out of. That well still produces 5 million a day. It’s actually a literally carbon copy for the type of stuff we are doing ultra deep from a performance standpoint. It made its first 24 Bs locked in at 40 million a day. And that’s kind of typically what you see on these high-pressure, deep gas wells in South Louisiana. And I’m sure you make 70% to 80% of your reserve flat life before you ever go and decline. This one went on decline when the water hit, but it’s still flowing 2,000 barrels of water a day at 7,000 pound floating up. That’s how strong the reservoir pressure is.

We’re going up dip to that. We have a PUD in the neighborhood approved undeveloped of about 20 Bs associated with it. I will tell you internally we think this area is much bigger than anything that’s on the books. We think it’s 100 to maybe 125 Bcf based on some pressure data we have from the producing well. And the key is making sure we understand where those sands are and where the reservoir is. So this well will go a long way towards getting us there. We’re also looking for some sands that didn’t tie in the first well, but we don’t think we are in the right track for that. So stay tuned. We have 6,000 feet left to go, 5,000 feet left to go. And hopefully, we’ll say out of schedule there to know something.

Phil Dodge – Tuohy Brothers

Pay attention. Thanks, John.

John Schiller

Thanks.

Operator

Our next question comes from Adam Duarte from Omega.

Adam Duarte – Omega

Hi, how are you? Question was asked. I'm all set.

John Schiller

All right. Thanks, Adam.

Adam Duarte – Omega

Yes.

Operator

Our next question comes from Steve Berman from Pritchard Capital.

Steve Berman – Pritchard Capital

Good morning, guys. Follow-up to the other questions on G&A expenses. So, backing everything out, what's kind of the normal run rate for G&A, including stock-based comp expenses looking out over the rest of the fiscal year?

David West Griffin

Right. Obviously, you have to back up $7 million associated with the Steve Weyel severance and then add to that another $1 million, $1.5 million or so associated with the run-up on the stock price. That sort of gets to your that number, backing those two out.

John Schiller

So $7 million or $8 million less than what this quarter was.

Steve Berman – Pritchard Capital

And on the operating expense side, you mentioned at the beginning of the call work-overs were the main reason for the increase in LOE. After Macondo, there were widespread expectations that the cost of doing business in the Gulf of Mexico would go up. Are you seeing that at all? And also, what could we expect on a BOE basis for LOE costs as we move forward here?

John Schiller

It’s hard to say we’re seeing a huge cost impact. I mean, you have few more man hours to repair a permit and some things like that. They are being much more diligent, and I would say that we had a rig inspected in the state of Louisiana. I don’t know that any of us ever remember the state of Louisiana dropping a rig inspector on a rig. Every rig that we’ve had working for us operated and non-operated has been inspected. But it’s not likely to shut down a rig because these can’t show up. It’s just the opposite. You came to work and they want to see working environment, what’s going on. So it’s hard to call that a productivity impact, if you follow me, Steve. And it’s kind of hard to even call it a nuisance. And it’s just that it’s there. It’s a new way of doing business. You may lose a day here and there because maybe once before you could ask for a day BOP extension, and now I don’t think anybody even bothers asking every two weeks, we’re testing the BOPs, come hell or high water regardless of what situation you are in. So, over the course of the year, that may mean that on a given rig, you test the BOPs two to four times more than you would have before. You lose two to four days of productivity. But it’s not a huge impact. It’s little things like that are really hard to measure.

Steve Berman – Pritchard Capital

Well, after a bunch of quarters with mostly a second team handle on it as far as the LOE per BOE, we hit the kind of mid-18s here. Do you see that as kind of a new rate going forward, or can you get back to the lower levels pre-Macondo, let's call it, as far as unit LOE expense?

David West Griffin

Yes. During this last quarter, we’ve had some additional production come on line. And so, as you ramp up production and fields et cetera, especially if you are starting production in the fields, you have an increased in LOE, personnel and everything out there. As you bring on your production, you start getting things more back in line. We are seeing a run-up in our production, level of production. And so I would expect that our LOE stabilized actually.

Steve Berman – Pritchard Capital

Okay. Thanks, guys.

Operator

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

Richard Tullis – Capital One South

Thank you. Good morning.

John Schiller

Good morning, Richard.

Richard Tullis – Capital One South

Looking at the production for the rest of the year, John, I know on the call early September, you talked about 4,000 barrels a day roughly coming on over the next six weeks or so. I mean, what's the status of that production component at this point? And what is your current daily production?

John Schiller

We’ve talked about South Timbalier at 2,500 barrels a day gross. The Main Pass well, they’ve given us about 2,000 barrels a day. East Cameron, one of those wells is on, one of them we’re doing some work on. You put all that in there, and as I mentioned at the start, we’re doing about day-in, day-out average run rate at about 27,000 right now.

Richard Tullis – Capital One South

Okay. What else do you have to come on near term?

John Schiller

Well, we’re drilling our second development well at South Tim. We’re about 3,000 feet from TD there. And then we’ll do a completion on that. And then Eugene Island 330, Apache is batch drilling those wells. So they have drilled three of them. Now they are going to batch complete. So we’ll have three completions on a well coming on there, which should be some decent volumes. And then we look forward to the Peterson offset.

Richard Tullis – Capital One South

What do you think those wells you just mentioned could add to the South Tier development – I mean, the South Timbalier development and Eugene Island 330?

John Schiller

We should probably, on a net basis, get someone (inaudible).

Richard Tullis – Capital One South

Okay. And on the wells where you were talking about South Tim 2,500 barrels a day and Main Pass 2,000, those are gross or net?

John Schiller

Those are gross.

Richard Tullis – Capital One South

What was your net number?

John Schiller

That’s seven or eight of those. (inaudible) 83%.

Richard Tullis – Capital One South

Okay. All right. Looking at the acquisition front, John, what are you seeing out there right now as far as packages available by various operators? And what's your capacity for going after those?

John Schiller

There are a lot of assets out there, Richard. You’ve got ENI talking about stuff. You have a Chevron package, Helix, ConocoPhillips, Exxon announced their deal the other day – who am I forgetting? A couple of more private guys have been contacting us. They are fairly large. So there are a lot other opportunities. We’re – as Steve mentioned, we look more at oil than we do gas. We think we have a world-class gas development already with the ultra deep. So we don’t see how we can be cost competitive with spending money on acquisition for gas versus what we already have on oil because of the breakaway difference in prices. You can pay less than $20 a barrel. You’ve got a pretty a pretty good op out there to drill and make some money on the oil side. It’s equivalent to what you make in a (inaudible). So that’s what we generally look at. In terms of the capacity, I think we feel very comfortable we can gear up to $1 billion with our balance sheet. There would be some things involved in that besides straight debt, mind you, till we would get there.

Richard Tullis – Capital One South

Okay. I mean, what would your timeframe be for doing a deal? I mean, are you open to doing one at any time? Are you looking to –?

John Schiller

And that thing you’re going to be able to choose when you do deals, they are going to come available when you can and then it’s up to my illustrious CFO over here to find the ways to finance it and obviously let some of the ultra deep developments occur and things like that before we forgot a pipeline. Of course, we got to find a deal, then we don’t have to worry about the rest of it.

Richard Tullis – Capital One South

Are you in any data rooms now?

John Schiller

Richard, we’re almost always looking at a data room. Ends it by new time because they are all virtual these days. Somebody looking at data almost every day, but we’re looking at a lot of those. We’re looking most of them and look for everything from ultra deep shelf acreage potential to just straight out, low down cases and everything in between.

Richard Tullis – Capital One South

Okay, okay. All right, John. I think that's all I had today. Appreciate it though.

John Schiller

All right. Thank you, Richard.

Operator

Our next question comes from Nicholas Pope from Dahlman Rose.

Nicholas Pope – Dahlman Rose

Good morning. I think a lot of my questions have been answered, but just trying to do a little cleanup on models. What is the production rate that you all are doing right now net for Eugene Island, the 330 area?

John Schiller

We’re doing production. Tom or Ben or Nelson, one of you got that number in front of you?

Unidentified Company Representative

I think it’s only – net production would probably be around the 300 to 500 barrels net from the existing wells that are out there.

Nicholas Pope – Dahlman Rose

That's fine. Thank you. And then, just with the Main Pass area, I mean, with – and – did you all see as good a production back up to where things were kind of excluding that pipeline downtime that you all had in the quarter ending in June? I know there is a downtime in the pipeline. Everything back to kind of normal in those – in that area?

John Schiller

Yes. All our pipeline problems are gone and things are producing good. What I might add, Nick, on the Eugene Island, just as we’ve talked about it couple of times and we may not have everybody remembering what went on out there. But that’s a field where Ike, Devon lost two platforms that have 30 wells on them, six of which produced, 24 which were shut in. That’s one of the reasons we don’t (inaudible) because as a company we started plugging our wells before storms could knock them over because those wells ending up costing us $4 million to $6 million each when they could have been done for $100,000. Those six well bores that we’re producing, though, had a fair amount of reserves associated with them. And that’s what we’ve targeted the front end of this development program where from another platform, drilling into those that we know we’re producing. We now drill three of those. They came in even better than we thought in terms of – they came in right where we thought the reservoirs would be structurally. We’ve put more oil in them than what we’ve thought. Some of that’s refilling and stabilization of the oil-water contact after a couple of years are not producing. So when it’s all said and done, we are very happy with that program, but it’s a redevelopment program into some reservoirs that haven’t been on for a couple of years because of storm.

Nicholas Pope – Dahlman Rose

Okay. Thanks a lot. That's really all I had. I appreciate it. Thank you.

John Schiller

Thanks.

Operator

Our next question comes from Joan Lappin from Gramercy Capital.

Joan Lappin – Gramercy Capital

Good morning.

John Schiller

Good morning, Joan.

Joan Lappin – Gramercy Capital

My question is to, after all the issues of last week and somebody asked you why nobody says pay and all of that. If we were to talk about Blackbeard East with or without water, if you didn't find another thing as you go down further, and I'm not suggesting that you won't, is that well sufficient – do you think there is enough stuff in that well to cover the cost that you've put in it so far?

John Schiller

That’s a tough question, Joan. That’s what we just know yet. That’s why we are mapping reservoirs and looking at P-10 and P-9s and looking at amplitudes on seismic and reflectors and trying to figure out where these fans go on the size of them. And so I can’t tell you an answer right now, which I could –

Joan Lappin – Gramercy Capital

Okay. But would it be fair to say that what you've found so far is gravy anyway and wasn't what you were looking for?

John Schiller

Sure. That’s fair. I mean, what we’re trying to get across everybody is we are seeing the sands that were never seen in the Blackbeard West. We now think that we have faulted and/or on conformity to how a huge section of the Lower Miocene. And so whereas at Blackbeard West, we jump from Lower Miocene into Oligocene, we think there is a big, big, big pod of sands left to be seen in Blackbeard East. Matter of fact, we have a correlation, and Jim Bob does back in to the Laphroaig well and a series of sands that we see over there. And the one thing I would say about Jim Bob Moffett, I’ve never been with anyone that could correlate large as good as he does. He doesn’t miss. And that goes back to 12 years of drilling with him. So we think there is a lot of sands ahead of us. That’s what was so frustrating about last week is there is nothing upside for where we are. We have a trap that’s working. We have hydrocarbon and we have reservoir quality rock. You can’t ask for anything more when you still have 4,000 feet left to drill to your planned TD and a sand interval in front of you. It doesn’t better than that, thick sand that loads up with gas.

Joan Lappin – Gramercy Capital

It also would seem to me that people would be noticing that Exxon poured cement down Blackbeard West, and you guys only – you went less than the amount of sand you have left to go to and found a huge discovery, which I'm sure they are sorry they walked away from.

John Schiller

Yes. I won’t speak for them, but the –

Joan Lappin – Gramercy Capital

No, but I think that's common sense. Now, to revert – last year, you were having trouble getting stuff to market because your pipeline supplier kept shutting down. So you built your own connection or whatever. I'm not exactly sure what you did, but you made a comment earlier about taking stuff to market. I mean, do you plan to do more pipeline building of your own, or was that just a necessity to get around an incompetent operator?

John Schiller

Well, it was a unique situation where we have – we could lay our line between Main Pass 73 and 61 and make it, Joan, what we call bidirectional. So we could flow oil from 61 to 73 or from 73 to 61, and one of those platforms has Shell taking their oil and one has Chevron. Chevron is the one who has the issues with the pipeline. And so we actually – we, by putting the line in to take all our oil to Shell, and there was a differential there, where Shell was paying a better price anyway. So the economies were like three or four-year payout on a pipeline, which isn’t bad. Then when Chevron got through redoing their pipeline, they put a tariff on it. And now it’s going to be probably less than a year or 18 months on the pipeline because they are saving over $2 a barrel moving all of our oil to Shell in that particular area. But those are opportunities to take advantage of when they come. We don’t see a lot of those across our infrastructure right now.

Joan Lappin – Gramercy Capital

Okie-dokie. Thank you.

John Schiller

Thank you.

Operator

Our next question comes from Jeff Hayden from Rodman & Renshaw.

Jeff Hayden – Rodman & Renshaw

Good morning, guys.

John Schiller

Good morning, Jeff.

Jeff Hayden – Rodman & Renshaw

Most of my questions have been answered. Just a couple of quick kind of modeling follow-ups here. John, if you look at the $47 million that you got from monetizing those derivatives, is that going to be amortized over the quarters going forward on the income statements?

David West Griffin

That’s correct.

Jeff Hayden – Rodman & Renshaw

Okay. And do you have the amount that's going to hit each quarter just kind of for modeling purpose?

David West Griffin

Yes, we do, in fact. I think we intend to, as part of the 10-Q when we file it, include sort of a summary of kind of how that layers in all the time.

John Schiller

And then, Jeff, just to sort of make it a little clear, we have $34 million cash in the door this quarter. The other $13 million is associated with October, November and December positions, which we just froze. And that money will be paid to us as a normal settlement for those gas hedges that are done, more or less.

Jeff Hayden – Rodman & Renshaw

Okay. I appreciate it, guys.

Operator

Our next question comes from Jason Wangler from Wunderlich.

Jason Wangler – Wunderlich

Good morning, guys. I wanted to kind of jump in on the back of what Jeff was asking. Just quickly, on the 2011 hedges, is there an optimal level you want to be on oil or gas, or are you pretty happy with where you are at or are you looking to add on either one?

John Schiller

Yes. Go ahead, West, you talk.

David West Griffin

On proved, we are really kind of looking – we are reasonably well hedged on the short end of the curve. We generally like to have some hedges out, looking at sort of a two to three-year sort of time horizon. And so we haven’t had the quite the length that we’d ideally like to have. And so what you’ve seen us do is add some additional hedges in fiscal year ’12 and a little bit in fiscal year ’13, and I think you’re going to see us continue to start layering in some longer term hedges, especially on the crude side. Our natural gas, as John mentioned, our philosophy is that hedge is cash. And so, taking money and setting it aside makes a lot of sense from our perspective. Consciously, when we unwound the gas hedges, we did some incremental crude hedges so that we had sort of a total revenue line that we felt pretty comfortable with in terms of our aggregate hedges. If gas prices rally et cetera, you will probably see us at some point start putting on some incremental hedges.

John Schiller

Yes. I mean, if you look at the number I threw out at you, we’re around 38% hedged on a revenue basis for the next 27 months through the end of 2012. That number you’d probably see go on to the 45%, 50% here over the next three, four months.

Jason Wangler – Wunderlich

Great. Thanks, guys.

John Schiller

All right.

Operator

And we do have time for one follow-up from Eric Anderson from Hartford Financial.

Eric Anderson – Hartford Financial

Yes. Just a quick follow-up, John, with what you've experienced so far in Blackbeard East down to the 26,000-foot level, how does this sort of set up your expectations for the Lafitte well that's in progress and also for the original discovery at Blackbeard West?

John Schiller

Yes. Great question, Eric. I tried to cover it in my opening remarks and maybe didn’t make much sense out of it though. We’ve now got one, two, three, almost four wells below the salt weld. That’s a ton of data, isn’t it, out of an area that has 60,000-plus wells drilled shallow. But each one of those wells is teaching us a lot. The one thing we are seeing that there is probably the most stunning of all is the huge amount of Lower Miocene interval that you can get through starting at 20,000 feet at the salt weld. And that has big impact all the way through the trend, particularly on the southern end of the trend, as I mentioned, Captain Blood, Lafitte and some of those wells. Those are things that, from a wildcatter perspective, you just dream about. We’re getting a tremendous amount of sand. We know the structures there. You can’t miss these structures now for the quality seismic we have. So, to start seeing this, this amount of sands, this tells you if I got a trap, I can get some big sand. Remember, 100-foot of gas on a prospect like Blackbeard or Lafitte, for that matter, is a TCF gas type reserves, maybe more. So yes, we are as excited as we can be. Every piece of data we get tells us there is going to be a lot of sand here. We’re seeing sands and we’re running on the plot.

Eric Anderson – Hartford Financial

Okay. Thanks for the clarification.

John Schiller

Thank you for the question.

Operator

I would now like to turn the floor back over to Mr. Schiller for any closing remarks.

John Schiller

All right, everyone. Thank you very much. We appreciate your attention. And as always, we’re available. If you want to follow up some more, give Stewart a call and we’ll continue talking. Thank you very much for listening today.

Operator

Ladies and gentlemen, this does conclude today’s program. You may now disconnect and have a wonderful day.

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