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Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

F3Q10 (Qtr End 03/31/10) Earnings Call Transcript

May 6, 2010 10:00 am ET

Executives

Stewart Lawrence – VP, IR & Communications

John Schiller – Chairman and CEO

Steve Weyel – President and COO

Analysts

Duane Grubert – Susquehanna Financial Group

Steven Karpel [ph]

Ron Mills – Johnson Rice

Steve Berman – Pritchard Capital

Richard Tullis – Capital One Southcoast

Nicholas Pope – Dahlman Rose

Joan Lappin – Gramercy Capital

Jeff Hayden – Rodman & Renshaw

Operator

Good day, ladies and gentlemen and welcome to Energy XXI third quarter 2010 earnings conference call. (Operator instructions) As a reminder, this conference call is being recorded.

And now, your host for today's conference, Stewart Lawrence. Please begin, sir.

Stewart Lawrence

Thank you, Tyron. Presenting today, we have John Schiller. We're going to make the call a little shorter than normal in terms of the formal presentation to leave plenty of room for Q&A. We'll, obviously, be – We've got the team here available to answer 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 release issued today and our public filing. We disclaim any obligation to update these forward-looking statements. While the Company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance. Our drilling schedules, capital plans and other factors may cause our results to differ materially. I urge you to read our 10-K and our latest 10-Q to be filed later today 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 third quarter demonstrated the benefit of the MitEnergy acquisition and our oil focus as we posted solidly profitable results. Our production volume rose 23% and our EBITDA jumped 33%.

You'll note that we significantly under-spent cash flow, allowing us to pay down debt by almost $60 million during the quarter. About $20 million of that was receivable to MitEnergy on the closing of the acquisition, post closing adjustments.

The free cash flow from operations was nonetheless impressive. At the end of the quarter, net debt was down to $609 million, with only about $71 million drawn against the revolver. That leaves a lot of availability should we need it for anything. And we definitely do not expect to need it to fund the drilling program, including our ultra-deep drilling.

Also on the subject of debt, earlier this week, our second-lien notes tender was completed and we expect to close that exchange today, making all but a handful of the notes freely tradable, one coefficient [ph]. I'm sure that will be helpful from a pricing and liquidity standpoint for many of you.

Now a quick update on the ultra-deep shelf. We continue to make excellent progress. Both at Davy Jones 2 and the Blackbeard East wells are ahead of schedule and under AFB. As of this morning, Davy Jones 2 is drilling ahead below 5,000 feet and our Blackbeard East well is drilling a head below 15,200 feet. Blackbeard East costs to date are $34 million, $5 million net to the company and we expect to be to the top of the salt for less than $40 million. Our next casing point will be around 16,500 feet.

Our Davy Jones task force continues to make good headway on the completion design for our ultra-deep wells. We plan on utilizing 25,000 pound equipment across the board to complete the Davy Jones number 1 well. We will complete the well for production between 12 to 18 months from now. Vendors have begun engineering designs on all the major components, including the tree, subsurface safety valve, tubulars and pumping equipment. We expect to have all major long-lead items ordered by early June.

We have no reason to believe that the timing or cost of any of this will be affected in the aftermath of the recent incident. Unfortunately, ultra-deep program in our third quarter results have been overshadowed by the rig explosion and oil spill in the deepwater Gulf of Mexico. We'll talk a bit more about this tragic event and what it means for the future of Energy XXI.

I'll start with a disclaimer that the cause of BP's tragedy is unknown, so nobody can claim it can never happen to them. What we can say is that our industry has over 60 years of experience drilling more than 60,000 wells on the shelf in the Gulf of Mexico without having a major incident like this one. In fact, the safety record over the past couple of decades has been excellent.

As the Wall Street Journal, said in an opinion piece Tuesday, the industry's record has been extraordinary, given the scope of its operations, with the amount of spill being miniscule. For our part, Energy XXI has consistently achieved environmental health and safety results significantly better than the industry average. We've even been a finalist for the SAFE award from the MMS.

We will also highlight some basic differences between drilling on the shelf and the deepwater. First and foremost, our BOPs are on the rig, not on the ocean floor under thousands of feet of water. Consequently, we don't need a riser for any of our drilling on the shelf. So what we're physically talking about is our BOP stack sits about 20 to 25 feet below the floor of our drilling rig. We can put men on it. We can manually shut in the BOPs in times of well control with all our automation cells.

One more point worth making is that blowouts often occur in shallow drilling situations. I'm not talking about water depth but, rather, the drilling depth, where an influx of hydrocarbons occurs relatively close to the BOP stack. That's because you get very little warning that a problem is heading your way.

In our ultra-deep drilling, it's just the opposite. We have plenty of time to react, just as we did when we took a kick at the Davy Jones number 1 discovery well. The bottom line is that drilling in deepwater and drilling on the shelf are two different animals. We'll have to wait for the result of the investigation. Certainly, if anything is learned that can be applied to shelf drilling to guard against such tragedies, the industry will adapt, as it always has, to these changes. So the questions we've heard repeatedly over the past several days are – What impact will the incident have on our operations? And what impact might we see in the ultra-deep shelf program, in particular?

I'll speak to current operations first. So far, none of our production has been affected and we don't expect any material interruptions. We saw slicks very early on in our Main Pass area. And, just today, we had one passing through the South Pass 49 area. We're monitoring our air quality and we continue to have no problems. Should we have something like that occur, the process, as we understand it, will be that the coast guard will come in and shut down boat traffic, to start with, so that they can work boons. Then we'll have– The MMS will come in and make a decision on air quality and other things as whether we can keep our production flowing or shut in. Right now, we haven't had any of our production get to the first one with the coast guard talking to us.

Our drilling operations are also unaffected. We continue to work over at South Tim with no problems. We have another one– We're finishing up one, we've got another one to follow there. Both of our McMoRan-operated, ultra-deep wells continue to drill. We're moving forward on permits for recompletions and development work in the Main Pass fields that we hope to start in early July.

And our pipeline-laying project in the Main Pass area, which is going to give us another option to get 73 and 61 to different markets, has continued without interruption. It's on schedule to be finished in mid-June.

There's absolutely no indication that there will be permitting issues. All appear to be moving ahead normally. The administration has clarified that they have no intention of shutting down drilling or production of any of the currently active areas of the Gulf of Mexico.

When you look at our ultra-deep, as I said, it's conventional shelf drilling. Yes, we have higher pressures but that's all we have. And we have a lot longer time to deal with them. And, in our business, as many of you have often heard me say, it's all about pressure differentials. As you learned from the BP well, you don't have to have a lot of pressure to have a lot of flow. That's why it's all about delta P. So that's kind of where we are on the technical side of things.

In summary, for the quarter, we had an extraordinary quarter. Let's not forget that it was in January that we announced Davy Jones as a major discovery. We remain absolutely convinced that we'll see continued success as we press forward at Davy Jones and Blackbeard, as well as with our core properties.

And, with that, operator, let's open it up to questions.

Question-and-Answer Session

Operator

(Operator instructions) Our first question is from Duane Grubert.

Duane Grubert – Susquehanna Financial Group

Yeah. Guys, can you talk a little bit about the non-deepwater program? Your development inventory that you revealed at your analyst day is robust. And, if we were to take a view just to get a prospective investor engaged in the quality of your program, what kind of production rates could you guys get to as a standalone company without ultra-deep exploration over the next three or four years with the kind of inventory you've got in hand now?

John Schiller

Thanks. That's a great question. As we unveiled, we've got 31 projects ready to drill today on the shelf in our core assets. The next big part you're going to see is in the Main Pass area, where we're going to do some of those infill wells. We're going to after some of the sands that we've seen on logs that are not on production. Probably, we're going to convert one of our water-disposal wells to produce, based on where it's located in some sands that aren't getting drained anywhere else.

And then, at South Tim, we continue to have other drilling areas. The only thing that's a little disappointing right now is that the market is – I don't know that I'd say it's heated up yet, Mark [ph], but we're going to be mid-July before we can get a rig that's necessary to do some of the Main Pass work. And, ideal world, we'd probably like to start that 30 to 45 days sooner.

But we've got a robust program. One of the things that we're dealing with over the next six weeks as we finalize our budget for fiscal year '11 is kind of what you just alluded to, Duane. There's some tradeoffs in there where, basically, you spend an extra $50 million in capital and you generate $100 million cash flow during the fiscal year. So we're going through racking and stacking right now all of our programs, looking hard at oil versus gas opportunities, which about 50% of our remaining opportunities are oil-driven. Out of that ready-to-drill list, that's about $300 million in capital ready to drill – 50% oil, 50% gas and somewhere around close to 20 million barrels of reserves associated with it. So you'll see, as we continue to look at those opportunities and we'll keep you posted as we put the rigs to work.

And with all that and, in answer to the final question, we should easily get with that program at sort of a 30,000 barrel range in the case of capital we've been talking about of like 250 and hopefully maintain it there and even have some growth over the next two years just on the core asset.

Duane Grubert – Susquehanna Financial Group

Okay. And, then, on this pipeline disruption and your decision to build your own – You described it as a bidirectional alternative. Can you walk us through how big of a project is that and what confidence you have in the timing of getting that done?

John Schiller

Yes. The key thing – Steve and his guys have done a good job. They looked and our marketing group looked, at all our different major platforms. And we kind of a year and a half ago decided, what we really wanted was two directions off every platform and how to make that happen. And this was the last one that we hadn't been able to deal with. We actually permitted it in January and got hung up in permitting over air emissions from the boats required to lay the pipeline and their impact on the Breton Sound, which is about 40 miles away from where we're laying the pipeline.

And this is a classic example of all the other work we've done, where there's actually an $0.85 per barrel differential on the tariffs between Shell and Chevron, so it's not only a pipeline that's going to give us a way out in case of shut-ins like Chevron's been having on their facility but also one that's economically attractive to us. And so it's – five miles? Eight miles?

Steve Weyel

It's right at five miles.

John Schiller

Right at five miles for $5.2 million. And, you've got payout in less than three years, about two and a half years on those economics. So those are the things we look to do to just continue to improve our infrastructure.

Duane Grubert – Susquehanna Financial Group

Okay. And then, finally for me, at the recent IPAA, you had said – Oh, we had hoped to have had some revelation on the Mykonos, but we had some delays. Can you update us on that?

John Schiller

Yes. Duane, I'm about to say the three words you never want to say in our business and that's high and wet. We drilled Mykonos. We saw the sand. We saw thicker. We saw everything we wanted, except the seal that leaked. We had crossover. We know there was gas there. That's why we had the amplitude. But what it looks like is the load that produced down bit stratographically pinched out. And that's why it was a trap in that the sand below it, even though that's where the amplitude was, had breached the seal at the fault. So that's a big disappointment. No way around that. We thought that would be a good-looking well. And, like I said, the three words you never want to hear is high and wet in our business.

Duane Grubert – Susquehanna Financial Group

Okay. You have our condolences. Thank you.

Operator

Thank you. Our next question is from Steven Karpel [ph].

Steven Karpel

Good morning, guys.

John Schiller

Good morning.

Steven Karpel

Can you walk us through, first, on Davy Jones where you are? I think you said that you have the equipment ordered here in June. Can you walk us through the kind of 12 to 18 months and talk about when you go to the MMS and kind of how that process works?

John Schiller

Actually, Steve, it's scheduled right now. Our first visit to the MMS to show them everything we have going on is going to occur later this month, as scheduled. And we actually are probably going to do some contracts with vendors later this month. And we should have them all done by early June. Some of it will be single-pad. For instance, on the tree and all, we're going to go one direction only because they've already built some.

Then there's things like the safety valve that we'll dual source. Tiebacks and connectors, we'll one source, all that's moving forward. Perforating is going to be a single source. We've already found what we need there with Schlumberger and some high-temperature chargers that can stay in the ground for 1,000 hours, which is going to allow us basically to do a buttoned-up completion where we run a TCP. We hang everything off, we put our tree up, we nipple down and then we perforate once we're hooked up to flow.

So we've been making a lot of headway. I know you guys get – on your end, you want it all detailed as quickly as I can. But I promise you, for an operation of this scope and technical challenges, the team is moving forward very rapidly. And the industry, as it always is – As we've talked about, we rise to challenges. We're finding a lot of things out that just keep this thing moving forward. The long-lead item time right now is the safety valve at 12 months. And those are guesses. It could be 8 months and it could be 14 months. We'll see as we get into it exactly where it ends up.

Steven Karpel

You mentioned about pressures and how you were probably less concerned about the pressures, given, one, kind of water depth and what have you. Could you elaborate a bit more on kind of the pressure differentials? And, of course, I say that in the context of the BP spill, given the correlation or the direction people are finding inclusions, people are trying to draw with you in the ultra-deep, I guess. Why aren't you concerned?

John Schiller

Well, I mean, pressure is pressure, but the big thing in our business – You've heard me say many times it's all about the delta P. For instance, at Davy Jones, everybody wanted to question the flow, it's all about KA, how many feet of (inaudible) you have and how much permeability. And the resulting pressure drop is what's going to determine your flow rate.

So it really doesn't matter whether you're drilling with a 9-pound mud and you take a 1-pound differential kick, or if you're drilling with a 15-pound mud and you take a 1-pound differential kick. Now the flow from the same block at those two intervals is going to be the same. And that's really what I'm alluding to. I mean, you're drilling with the same things. You could get a pound under balanced through a kick anywhere, regardless of the pressure in the reservoir. It's still about the delta P. Yes, when you're in a completion mode, your shut-ins can be different and that's why we're designing 25,000-pound equipment for this thing. Those other wells won't have as much shut-in pressure. But, in terms of flow and well control, it's all about delta P.

Steven Karpel

And then just kind of one last question in terms of permits. I know you mentioned that things are still going. That's the message we've been hearing from others. What do you need permits for, kind of in general, across the portfolio?

John Schiller

Without going back to step one, for most of our fields where we've – You start with a plan of exploration when you drill your wildcat. Then you come up with a development plan. Most of our, obviously, large, producing fields have already had development plans filed. And all we're actually going after are well permits, which are typically, a 30-day sort of process. But the development plan could be a 90-day sort of process and that type stuff. All of our stuff is there. So we're typically looking for permits just to drill or to work over and recomplete a well.

Steven Karpel

Thank you, guys.

John Schiller

Thanks, Steve.

Operator

Thank you. Our next question is from Ron Mills. Your line is open sir.

Ron Mills – Johnson Rice

Good morning.

John Schiller

Good morning, Ron.

Ron Mills – Johnson Rice

A couple of questions. You said that both Davy Jones and Blackbeard East are ahead of schedule. Are you talking about drilling time? It's just like on well cost. But what's the expected timing site? I think both of those wells were originally expected to take 200-plus days to drill.

John Schiller

Yeah. That's right, Ron. I don't know that we're going to adjust that yet. All I'm telling you is we are ahead of the drill-day curves and we're ahead on the cost curves. Getting to the salt at $40 million at Blackbeard would put us substantially ahead of where Exxon was at the time, just to give you some sense and puts us ahead of our curve by 15%, maybe 10% to 15%.

So we continue to just watch it down. I mean, the general comment is, when we're drilling, we usually beat the curve. We're drilling faster with better P rate. And that's one thing people have missed. But we've consistently done that across all this ultra-deep drilling. All the way back to Blackbeard at 33,000 feet, we were making 100 foot and 150 foot a day. And I can tell you from a guy that drilled a lot of Oklahoma wells in my early Burlington days. We'd kill for those rates when we used to get 75 feet a day at 18,000 and 19,000 feet in Oklahoma.

So we've been very impressed with P rates and that's what we're seeing on these wells. We continue with the new bit designs. With the underreamer assembly that we're using, we're doing this stuff with one pass. Our P rates have been better than anything we'd predicted. And where we need to continue the work on improvement is on what we call our flat spots. For instance, on both those wells, we had to re-squeeze shoes on the last casing line on each well. But that's the first one we've had to squeeze and hopefully will be the last one.

Ron Mills – Johnson Rice

Okay. And just a little clarification on, so to the pipeline rupture. In your press release, you talked about, at the end of March, production being at 27,000 BOEs per day and that included the impact of the remaining 1,300 barrels a day that had been shut in from the storms. And so I would assume, then, that your current production is somewhere in the 24,000 to 25,000 BOEs per day. Is that the right way to look at that?

John Schiller

It's going to be a little bit less than that because we've got some decline going on too. So what I will tell you is we're running probably – For April, we ran just shy of 24,000.

Ron Mills – Johnson Rice

Okay. And, in May and June, do you have any wells being hooked up or recompletions or work-overs that can impact that or is the fourth quarter for you all going to be one of just some natural declines?

John Schiller

We've got the two work-overs at South Tim and we've got some non-operated Apache activity that's going on. I will tell you that we'd do good to stay flat without getting the pipeline production back on. What we're going to do is just keep you guys posted because, we told you when our pipeline is going to be ready.

Chevron's estimates are all over the board, as they typically are. So we'll just have to see where they come back on. They're latest is they're going to be ready before us. But they started out they were going to be ready a month after us. So let's just see how they're repairs go. The deal we'll make with you guys is we'll make sure and tell you when our production is back on.

Ron Mills – Johnson Rice

Okay. And maybe just some clarification for me because I'm not real quick, when you all talk about production capacity of 30,000 BOEs per day, that's not necessarily production guidance. That's just what you are capable of producing. Or is that a level that you think you can actually get to and sustainably produce?

John Schiller

Yeah. When we talk about capacity, we're talking about, if we have no downtime on any field, that's what we'd make that day. Okay? And every once in a while we have a day like that but most of the times we have a compressor gets shut off or high pressure, low pressure, or a couple wells load up and we've got to go unload them. Those types of things is what impacts your daily production versus your capacity.

Ron Mills – Johnson Rice

Okay. And so, when we look at your overall production run, is there –? Is there any kind of range where that downtime and, or delays or anything that typically runs – ? Is it 10% to 15% type downtime relative to capacity or?

John Schiller

We're shooting for 90% to 95% of capacity is where we should. 95% is about the best run time you're going to get. Because of the amount of oil and the fluids that we handle, that's probably not always achievable for us. It's more achievable on gas production than oil production. Oil, you're handling so much more fluids. I can make 5,000 barrels a day out of South Tim. We're currently making 30,000 barrels of water a day. So it's the fluid-handling stuff that causes a lot of your downtime.

Ron Mills – Johnson Rice

Okay.

John Schiller

That's the beauty of the beast of oil. It's the reason that oil costs more to get out of the ground, but it gets a lot better price. So at the end of the day, it's a battle we'll gladly fight.

Ron Mills – Johnson Rice

And then lastly, Lafitte is, as I recall set to spud once the new rig gets off on its – I guess test location, if you will. What's the latest on timing on Lafitte?

John Schiller

Well, actually Jim Bob and all of us went down and dedicated that rig last Saturday. Jim Bob gave a very nice speech around it. As we currently understand that rig – he's going to take it for a shakeout like he did on the last one at a reduced rate and make sure everything's working the way we want it before we put it on one of these ultra-deep wells. But my guess is still later this summer we should be on the Lafitte well.

Ron Mills – Johnson Rice

All right. Thank you very much.

Operator

Thank you. A next question will come in from Steve Berman. Your line is open, sir.

Steve Berman – Pritchard Capital

Good morning, guys. Ron asked most of my questions. But John, if I could ask you to opine a little bit and kind of look at a little further down the road on the BP oil spill as to what impact you think we might see on regulation and maybe more importantly, insurance rates and how those might go up and possibly impact a company of your size.

John Schiller

Steve, we barely – I heard something about the insurance costs. I'll answer that one. But I didn't quite catch the first part.

Steve Berman – Pritchard Capital

The first part is just your thoughts on new regulations and what you might see there?

John Schiller

Right. Steve comment first on insurance. We're actually in the market.

Steve Weyel

Yeah. We went into the market early this year. Obviously, the BP incident is a big negative for the market as far as Gulf of Mexico exposure. That said, the capital markets are still very robust, which underlines or are behind the economics for the underwriters. And they've kind of thrown indicative numbers out there.

So we definitely will see upward movement with the liability cost associated with our program. But we don't think it's going to – it's probably going to push the rates a little bit back more towards the norm. They were headed for pretty strong freefall from last year. So we feel comfortable that capacity will be there. It will be there at a decent price and we'll be able to get what we want in the marketplace.

John Schiller

And in real numbers, so you understand we were talking – remember we bought MitEnergy. So you can't take this across all companies, okay. But for the combination of Mit and Energy XXI, what we paid last year, we were heading towards a 50% reduction in premiums. What we really need from an insurance standpoint is to get this well capped get it under control, keep the oil from getting onshore. And then I think we'll see the market settle down.

From a regulatory standpoint, the answer is very similar. I think that it's all about how much heat the administration ends up taking from oil on the beach versus letting it dissipate and evaporate offshore. And I think that will have to do with how they regulate.

As you heard me talk from our sense, it's hard in our mind to connect what we do on the shelf with what goes on in deepwater. They're just two totally different operations technically with regards to riser and BOPs on the floor and working with ROBs versus being able to put your hands on the stack like we do.

So I'm sure that there are some things they can do as we find out the actual facts behind it. They may be as much procedural as they are with regards to technical specs on equipment. They may just come in and mandate how the procedures are to manning a well and things like that. We'll just have to wait and see.

Steve Berman – Pritchard Capital

Great. Thank you very much.

Operator

Thank you, sir. Next question will coming is form Richard Tullis. Your line is open.

Richard Tullis – Capital One Southcoast

Hey, good morning.

John Schiller

Good morning, Richard.

Richard Tullis – Capital One Southcoast

Just a couple more questions following-up on what some of the other folks were asking. Going back to Mykonos, I know it was breaking up a little bit. Could you talk about the issue there, John?

John Schiller

Yeah. I mean we have this button here that we break up when we don't want you to hear the answer, so it's a neat situation. At Mykonos, we drilled the well and came in geologically right where we wanted it to be. And like I said, the three words you don't want to hear are high and wet. And we saw the objectives. We saw them up-dip over 100 feet high nice, thick, clean sand.

We had the porosity crossover, which tells you there was gas there, but there's no gas there now. So our best guess is that it looks like the fault that we were hoping to seal was a breached fault. And so you had gas trapped there once upon a time and it went out. And that's always – the dirty secret that people don't always talk about when they drill amplitudes is it only takes 5% gas saturation, which is much less than residual gas when gas has been depleted from an area. It only takes 5% to create the sag on your segment that creates an amplitude.

So what it looks like is– We had pay down dip in a separate load. It looks like that load must stratigraphically trap before it gets to the fault and that's why he had gas there, whereas all the rest of the gas had bled off through the fault.

Richard Tullis – Capital One Southcoast

What was your cost on that well?

John Schiller

I'm sorry. What?

Richard Tullis – Capital One Southcoast

What was your cost on that well?

John Schiller

See, needed for – just shy of $5 million.

Richard Tullis – Capital One Southcoast

Okay. And you don't plan on re-entering or doing any more work on it?

John Schiller

No.

Richard Tullis – Capital One Southcoast

Okay. CapEx, any update for the expectations for the second half of this fiscal year and then all of next fiscal year?

John Schiller

CapEx?

Richard Tullis – Capital One Southcoast

Yeah.

John Schiller

As I mentioned earlier, we're going to look hard for our budget. We'll have a budget board meeting July 15. We pre-limit in early June to the board. And basically, we've got two scenarios we're looking at right now. One is the 250 we've talked about and what it does for us. And one is a hard look at, if you spend another $50 or $75 million on top of that. And you do some things like buy some puts or something with collars so that you protect the oil production you might bring on, what does that do for you?

Right now, we've run some cases where, basically every dollar we spend gets us $2 back during our fiscal year '11. So as strange as it sounds, but that's the beauty of the economics in the Gulf of Mexico, you spend more money. You make more cash flow. You pay down debt faster, especially where rig rates are.

So we're going back and forth looking at those two options and continue to fine tune and really look hard at the technology involved with predicting what we're going to get from these wells. You go back to Mykonos and everything you had tells you to drill that well every time. So we've got to make sure we understood what happened there and that we don't get burned like that elsewhere, if you're going to spend more capital.

Richard Tullis – Capital One Southcoast

How much of the pipeline lateral at Main Pass is completed at this point?

Steve Weyel

The line's actually been laid, Richard. We're just in the process of tying everything back a those units.

Richard Tullis – Capital One Southcoast

Okay. And you said likely in service end of June?

Steve Weyel

Early June.

Richard Tullis – Capital One Southcoast

Okay. And what's the production impact per day? Was it 2,500 barrels a day?

John Schiller

Yeah. That's in the neighborhood.

Richard Tullis – Capital One Southcoast

Okay. Going to the shelf prospects – I know you mentioned the 31 that you have in the portfolio inventory. What's the timeline as of right now for drilling those over the next 12 to 18 months, particularly Crete and Cohiba?

John Schiller

We've got two workovers going at South Tim. We just finished one of them today. At Main Pass, it looks like it will be kind of mid-July before we can get a rig that can get over the platform where we want to start the work. And the work there is going to involve a workover at a couple of drill wells.

At the same time, we'll probably be looking for another rig in South Tim and do a couple of the infill drill wells there that we want to get done. We've got Apache. They run a pretty robust, non-operated list of drill wells for us, both in the Golden Meadows area of south Louisiana, where we've had a very nice run with them. I think we're one out of seven (inaudible). We've had one dry hole of seven (inaudible) with Apache.

And then Apache, they took over Eugene Island 330 prior to the acquisition with Devon assets. They had already cut a deal to take over 330 and they're proposing three wells there. We think that's the first of a series of what's probably going to be about nine wells. And we own about a third of those. That's another big oil field. They're all oilfield plays – all oil producing plays.

So we've got that, that's about $30 million to $40 million in CapEx over the next 12 to 18 months there. And then at Eugene Island 275, we're going to do a little work also on recompletion.

Richard Tullis – Capital One Southcoast

What about Crete and Cohiba? When are those scheduled for?

John Schiller

Crete? We're starting to get the rig – seismic back. We still have that targeted for the end of this calendar year to spud. I think at Main Pass, you'll see us get Ashton drilled fairly shortly here. We're trying to focus on the early drilling on oil wells where we know we have oil. That's the biggest differential right now for us.

Richard Tullis – Capital One Southcoast

Okay. And I think lastly, I know you touched on this already. I guess the safety valve is one of the big key components or the big key component inflow testing and getting Davy Jones on production. What's the process there the timeline? How far along is this? Is it still in the spec stage or how do things look with that? Who's actually building it for you?

John Schiller

Yeah. The safety valve itself we're going to have both most likely, Halliburton and Baker on a dual source there. So they're each designing a 25,000 pound safety valve. Between those two for various reasons, I won't say which way is which right now. But their estimates are between 12 and 18 months, the difference having to do with testing facilities more so than the actual design of the valve.

You're talking about modifying an existing 20,000 pound valve, so we're not talking engineering from the ground up. We're talking about a redesign. And that's why we continue to feel pretty good on the time estimates we give you.

I think, if you didn't pick up on what I said, that we're going straight to a completion now. There is not a designated separate flow test. We think we'll have everything we need in 12 months to go out there, complete the well, tie back the casing run our tubulars, run our packers, run a TCB perforating done, nipple everything down, hook up the tree to the flow line and put it on production. So that's kind of how that flow test will work.

Steve Weyel

And just to clarify, that's right in line with what we've been saying. Part of the program was to have a flow test only by somewhere around yearend or early next year and we're skipping that stage.

Richard Tullis – Capital One Southcoast

Okay. What are the facility requirements for this first well? I mean will that – you're going to have all that in place as well?

Steve Weyel

Yeah, Richard. We planned to take the first well, the Tiger Shoal facility and use the existing production facility. The only real criteria outside of that is what we'll do to mitigate some of the high temperature at the surface itself. So it's pretty straightforward. And again, that's all been done, as an example, in Mobile Bay. There's nothing new with that.

Richard Tullis – Capital One Southcoast

Okay. All right. Very good. Appreciate all the time.

Steve Weyel

You're welcome.

Operator

Thank you, sir. A next question will come is from Nicholas Pope. Your line is open, sir.

Nicholas Pope – Dahlman Rose

Good morning, guys.

John Schiller

Good morning, Nick.

Nicholas Pope – Dahlman Rose

Just to kind of clarify, I mean I think kind of an interesting point with Davy Jones that you are heading straight to completion as opposed to just a production test. Could you clarify that? Are you going to be tying directly into facilities and be able to produce immediately with the completion? Is that what I heard?

John Schiller

Yeah. That's what we're talking about. We have what we need to be able to flow the Tiger Shoal. There's now – let's put it this way. The completion itself will be set up to where it's ready to flow to facilities. It's maybe a little early to tell you whether it's actually hooked up and flowing and selling or whether we flow it through some sort of test facilities.

But we're doing this thing one step at a time and reporting real time to you guys. And then you all get all upset when we give you a number that's a month difference between the three of us, just like I told you it was going to be. So what I'll tell you is the tree and everything will be nipple down in 12 months. Let's don't go yet on whether we test it at the sell facilities or whether we test it at the temporary facility.

Nicholas Pope – Dahlman Rose

Okay. That's good. And I guess whenever you look at this well at this point with I mean as you all have gone through the design with the data you all have. What do you view as I guess the major risk in terms of the predictability of Davy Jones at this point?

John Schiller

Nick, I think one of the things you have to keep in mind here that people are tending to forget is that we're going to have the offset well, we'll already be drilling into these intervals easily before we get to testing this well. If it comes in the way we expect with the continuity of the sands. We're going to be able to go in there and get cores. So we're going to have a much better idea of the sand. We're going to have our porosities and permeability’s nailed down better than we do now.

We'll probably have a better feeling for the reservoir fluids, which will let us predict a better shut-in pressure. Because remember with what we know today, yes, we're designing everything for 25,000 pounds but we can show you where the wellhead pressure can be anywhere from 18,500 pounds to 22,000 and we might not even need 25,000 pound equipment.

So all of those things we're going to feel much better about once we get this second well down and we've been able to use its data to help analyze more about the reservoirs we've discovered.

Nicholas Pope – Dahlman Rose

That's great. And then just finally, do you all have a breakout of production for the first quarter in your different regions, like central Gulf, Eastern Gulf, onshore? Do you have that breakout?

John Schiller

Yeah. We'll get it to offline. I don't know that we have it posted anywhere.

Nicholas Pope – Dahlman Rose

Okay. No problem. And that's all I have. Thank you.

John Schiller

Thanks, Nick.

Operator

Thank you. A next question will come is from John Lappin. Your line is open.

Joan Lappin – Gramercy Capital

Good morning, everybody.

John Schiller

Hi, Joan.

Joan Lappin – Gramercy Capital

I'm wondering if you can amplify a little more what your view is of the government and the problems in the Gulf at the moment and what you think its long-term impact is going to be on your industry, to the extent that anybody can know. I mean you did make a brief comment about that a few minutes ago. But I wondered if you could expand on what you think is likely to happen?

John Schiller

Yeah. Again we don't know for sure what happened. My general comments are I think the whole industry has pulled together behind BP. We all know it's an industry problem. There's a lot of smart guys over at BP's office from other companies besides BP working on solutions. There may a lot of handling solutions. I think it's easy for the media to get out there and kind of rewrite the story. But the truth of the matter is for the first two days, you had a fire burning on a rig and there was no slick to speak of. Yes, a little bit of it but all the hydrocarbons coming up for the most part were being consumed.

So I think the government responded appropriately. I think the industry has kicked in. There is a lot of myths out there, Joan. For instance, over the weekend when the wind was blowing so hard and you had all this – the size of the slick has tripled, so there must be more production. No one wants to just state the obvious, which is with the winds breaking up the slick, it thinned out and took over a larger area. But the thinning was a good thing because it started evaporating. And next thing you know, you've got a smaller spill area.

So all of that is – we go through MMS drills regularly here both on our own and both where the MMS walks in and says it's time to do a spill drill boys and girls. And we know how to handle those things. We know how to predict where the spills are. We know how to go out there and fight them.

The fact it's staying offshore right is obviously helpful. I think that they've got a very high chance of getting this thing capped pretty quickly. And then I think how much of that ultimate damage comes out there is what's going to determine where the regulations go. But again, if I go (inaudible) calculation with you – we showed you guys what goes into getting a drilling permit, like we talked about getting one a while ago.

All the calculations you do – your maximum anticipated pressures, all those type things are very stringent. It's not like we just dream these equations up overnight. They're proven. They've been proven by EPI. So we go through a process. MMS goes through and documents it. And then everything out there is going the way it's supposed to go. And I think you'll see as an industry, we've done a very good job of that. That's why we very rarely have incidents.

Joan Lappin – Gramercy Capital

So to go back to Davy 2. You've made quite clear that you expect to have pretty good info more than results on Davy 2 long before a year from now. So and there's supposed to be something of an up-dip there. So at what depth are you hopeful, because that's all you can do at this point? Are you hopeful that you're going to run into some productive sands? I mean I assume it's not 29,000 feet, it's less?

John Schiller

No. But it's not that shallow either. At Blackbeard East, once we go below the salt at about 22,000 feet, we come into potential hydrocarbon zones all the way down the TB at 30,000. At Davy Jones, we know where the top of the hydrocarbon pay is. And that's going to be somewhere plus or minus 500 feet around 27,000 feet. 27,000 feet is where we definitely started to see the sands in Davy Jones 1. We should be about 500 feet uphill.

What we had hoped to see at Davy Jones 2 is a log that looks just like what we have so far plus, as we drill deeper pick up additional sands because remember, we don't believe we're out of the Wilcox yet to start with. So we think there's more sand down there and some of the more prolific sands still to be seen. And then we hopefully have the Cretaceous that we can get to our Tuscaloosa never set.

Joan Lappin – Gramercy Capital

And what do you think is going to be the next event for your company that's going to make people happy? I mean your announcer guy basically invited people to make comments. And my personal comment is this is just like a year or so ago when oil was at $30 a barrel. And people were dumping the stocks like there was no tomorrow. I mean it seems to me when there's something bad happening, that's time to get into this group. But what do I know? I've only been doing this for a few decades.

John Schiller

Yeah. And history definitely proves you right on that. So I think you look at the quarter. I think this is a quarter where you really start seeing the difference between those of us that are truly oil – 68% oil. We have less than 1,000 barrels a day of NGLs in our number. We make real oil. It gets the full WTI price. Actually, in our case with Brent where it's trading, we get WTI plus. So you're starting to see in this quarter the differences. As you know, 68% oil equated to 84% of our revenue stream for us. I think you're going to start seeing we've got a big, strong underlying asset base.

I think, over the next couple of months what you're looking for as a significant event are two things. A, we will continue to look at the M&A world. We don't anticipate doing a $1 billion. Bu, if there's an oily property out there and there's some for sale, that makes sense that we think we can get synergies around and get a lot of drilling opportunities out of, then we'll pursue it.

Second is that Blackbeard East has got to be – literally, we could be 60 days to seeing – getting into those top sands. And the significance of that is that, if we log pay above about 25,000 feet and pressures are where we think they should be, then we've got a high probability that 20,000 pound equipment will work. And now you're talking about, frankly something that you could have tested and on production before you even do the Davy Jones test.

Joan Lappin – Gramercy Capital

Sounds good. Okay. That's it for me.

Operator

A next question is from Jeff Hayden. Your line is open, sir.

Jeff Hayden – Rodman & Renshaw

Hi, guys. Just to follow-up to some of the other questions that have been asked. I'm kind of looking at the development of Davy here. If I'm hearing it right, we're probably talking maybe middle of next year before we see production from Davy. Now, given that we're going to have the Davy 2 probably drilled, how should we think of the timing of when we could see production from Davy 1 versus Davy 2?

John Schiller

Yeah. I mean just the modifications we're doing and the design work we're doing will be applicable to all the wells, okay? We're doing both 25,000 and 30,000pound designs. So a deep Blackbeard well ought to be on production, as will the Wilcox type wells at Davy Jones. Davy Jones 2, if you go through the timing, where we are today, we should be reaching TD during the fourth quarter of this calendar year. So you know what you have there. You learn something from the sands. It's very conceivable that you'd have both wells on production by the end of calendar year '11.

Jeff Hayden – Rodman & Renshaw

Okay. Great. And then just kind of looking at sort of the core shelf stuff, how should we think about fiscal 2011, kind of excluding the ultra-dip as far as production goes? I mean do you expect to kind of expand upon that 30,000 barrel a day capacity number or should we sort of think of that as kind of baseline and then run kind of 90 or 95% off that to kind of get to sort of the 2011 production rate?

John Schiller

Yeah. I think we can get capacity probably 5% higher than the 30 so 31.5 or 32 barrels a day or somewhere in there and look to actually have production running close to 30,000.

Jeff Hayden – Rodman & Renshaw

Okay. I appreciate it.

John Schiller

All right.

Operator

Thank you, sir. And this is the Q&A session. I would like to turn the call back over to your host.

John Schiller

I appreciate everybody for coming on board. We appreciate you taking time out of your day to listen to us. We know there's a lot of things out there today. If you've got any questions, follow-up with Stewart and us, and we'll get back to you. And have a good rest of the week. Thank you.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program. You may now disconnect. And have a wonderful day.

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Source: Energy XXI (Bermuda) Limited F3Q10 (Qtr End 03/31/10) Earnings Call Transcript
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