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Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

F2Q09 (Qtr End 12/31/08) Earnings Call

February 10, 2009 10:00 AM ET

Executives

Stewart Lawrence - Vice President of Investor Relations and Communications

John D. Schiller, Jr. - Chairman and Chief Executive Officer

David West Griffin - Chief Financial Officer

Steven Weyel - President, Chief Operating Officer

Analysts

Neal Dingmann - Dahlman Rose

Duane Grubert - CRT Capital Group LLC

Evan Templeton - Jefferies & Company

Richard Tullis - Capital One Southcoast

Stephen F. Berman - Pritchard Capital Partners, LLC

Michael O'Brien - Collins Stewart

Jeff Miller - JMG Capital Management, LLC

Sharath Reddy - Redwood Capital

Biju Z. Perincheril - Jefferies & Company

David Ambler - Global Credit Advisers

Gaius King - W.H. Ireland

Operator

Ladies and gentlemen, good afternoon. At this time, I'd like to welcome everyone to the Energy XXI Second Quarter Fiscal Year 2009 Earnings Conference Call. During today's presentation, all participants will be in a listen-only mode. A question-and-answer session will follow the company's formal remarks. (Operator Instructions).

I will also give these instructions after management completes their prepared remarks. Just as reminder today's conference call is being recorded.

At this time, I'd like to turn the conference over to Mr. Stewart Lawrence, Vice President of Investor Relations. Please go ahead, sir.

Stewart Lawrence

Thank you, Christina. Presenting today is John Schiller, our Chairman and CEO; Steve Weyel, President and Chief Operating Officer; and West Griffin, our Chief Financial Officer. We'll be available to answer your questions at the end of the call.

Before we get started, I need to remind everyone that our remarks today, including answers to your questions, include statements that we believe to be forward-looking statements. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include, among others, matters that we've described in our earnings release issued today and in our public filings. We disclaim any obligation to update these forward-looking statements. While the company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance. Our drilling schedules, capital plans and other factors may cause our results to differ materially. I urge you to read our 10-K filed yesterday to become better familiar with these risks and our company.

Now I'll turn the call over to John.

John D. Schiller, Jr.

Thanks, Stewart. Welcome everyone to our second quarter conference call. Our industry is facing many challenges. Oil and gas prices have fallen faster and further than any time in the past thirty years.

During the past two quarters we and the industry have responded by repeatedly reducing capital spending plans with these stated incentive statement (ph) within cash flow.

With a continued drop in prices, we now expect spending to exceed cash flow for our fiscal year. Fortunately we have sufficient liquidity to avoid raising external cash in this depressed market. Our going-forward plan is to hunter down, we will fulfill the current capital programs commitments, which means cutting spending to less than $100 million for the second half of our fiscal 2009 which should keep us within cash flow. That spending level includes hurricane repairs and our cash P&A cost.

By the time we get our fiscal 2010 beginning July 1st, we expect to return at less than $10 million per month at our capital expenditures or about a 100 million for all of fiscal 2010. We are also targeting a 10 to 15% reduction G&A and we expect a 5 to 10% reduction on direct gallery largely due to lower service cost.

The primary focus in the foreseeable future is preserve capital, reduce debt, with the target debt reduction of more than 100 million in fiscal 2010. Now we continue to have significant upside from the drilling program and we forget about our opportunities to build a stronger company as we emerge on the other side of this industry downturn.

We're achieving good things here; production has topped our expectations in both the first and second quarters of fiscal 2009 even though hurricane affected volumes continued to be delayed by the third party pipeline repairs. Our own facilities will be repaired and placed back on line very quickly; I am proud with what our team was able to accomplish.

In January we were back up to 85% of pre-storm volumes compared with about 75% for most of our Gulf of Mexico peers. Second quarter volumes were helped by the success of our development program, particularly, within the South Timbalier 21 field. The new Barolo development well came on strong, and we expected another (inaudible) production over the -- once the Giddip (ph) well finishes its re-completion.

Our Main Pass 61 third also has been a solid performance. We're getting good things out of the Main Pass 60, we expect good things out of Main Pass 61 water-injection well we just finished drilling which should raise the fill's production rate and increase sales with recovery reserves.

Recently, our production has averaged more than 21,000 barrels a day equivalent with the capacity to produce about 24,000 barrels a day when everything was back on line. While production volumes are strong, oil and gas price is obviously hard cash for those (ph). Our hedge has been a tremendous help in managing the downturn adding more than 24% or $11.5 a barrel oil equivalent for realized prices in this quarter alone. Still, the price drop, it had an impact on both current cash flows and indicated future cash flows with showed up in a ceiling test impairment we reported with our results yesterday.

By now, you probably heard more about ceiling test you ever hoped to hear; industry reports a rash of these non-cash impairments every time prices plunge and they rarely reflect the true disruption of value. The test is run using future revenues based on end-of-the-quarter oil and gas prices; in our case, about 44.60 for the oil and 5.71 for the gas netted against the end-of-the-quarter cost structure and discounted back to present.

Biggest problem with that calculation is that prices did in fact hold at these levels long-term, cost structures naturally would decline in response. That said neither us nor the future's market believe oil and gas prices should stayed depressed for the long-term.

On the exploration front we've had mixed results in the past few months with a couple of major efforts still pending final results.

In Cote de Mer we've made a sizable natural gas discovery although so far it's not proved to be the giant we'll hope going to find. I'd say we are not quite finished yet with two more targets and to drill, which could hold a large amount of gas. During the past weeks, we've been fighting mud losses, good news is we've got it under control, went back to drill one last (inaudible) and with less than 600 feet to go to achieve, we hope unless you know the outcome within the next couple of weeks. We made about 70 feet overnight since we went back to drilling.

The high profile well we're drilling right now is Ammazzo, which is a look alike to McMoRan which is a Flatrock discovery. On Rowan's new jack-up rig we're using arrow-heads (ph) and commissioning downtown, but it's been making good progress of late.

In addition, with the Blackbeard discovery, we remain very optimistic as we continue to collect data and plan for the well completion and flow test.

A key point is that is that even without capital expenditures being greatly reduced, we have both development and exploration projects under-well -- underway that can make meaningful contributions to volumes and reserve additions.

Now, I'm going to turn it over to West for financial review.

David West Griffin

Thanks, John. The financial detail was in the earnings release. So, let's look at the noteworthy and unusual items. The second quarter compares favorably with the first quarter, both included hurricane effects, particularly on volumes. Workover and maintenance expenses were up this quarter because we expensed a portion of our hurricane insurance deductible. That totaled 2.2 million for the quarter, which means we would have been in line with previous quarters excluding this item.

Production taxes and other ended up being a benefit $3.25 per BOE due to gains on derivatives, which added $5.69 per BOE. Without it, that impact, production taxes and asset retirement obligations were in the normal range. With volumes increasing, our underline cost per BOE of production were reduced in the second quarter, which lead to EBITDA of nearly $39 per BOE for the quarter.

Financially, guidance that are within our control are moving in the right direction. Now, to update our liquidity position. These numbers will be slightly different from what you'll will see in the 10-Q since we've updated them as private. We still have 33 million of cash at the corporate level and an additional 10 million at the operating level. So, in total on February 6, we had 63 million of cash on the books.

The 86 million of capacity remaining on the revolver excludes 20 million associated with Lehman. Short term liquidity, therefore, totals a 149 million. In addition we hold 126 million face amount of bonds with a current market value of approximately 58 million. With that I will turn it over to Steve.

Steven Weyel

Thanks West. The 19,200 barrels oil equivalent per day of production reported for the second quarter was solidly above our expectations even without the expected restoration of hurricane volumes. The weather offshore has delayed third party pipeline repairs given our core properties had enough good news items to offset the delay.

January averaged about 21,500 barrels oil equivalent a day and we are currently at approximately 21,000 barrels per day. So the March quarter should show another nice improvement. We have a number of wells in progress that contribute good volumes in the second half of our year including re-completion of goal (ph) at South Tim 21, the injection well at Main Pass 61 and the Golden Meadow discoveries onshore.

Growth in the fourth fiscal quarter will depend on the timing of the remaining pipeline repairs. It should be safe to assume we will average more than 20,000 barrels per day for the full fiscal year.

Looking ahead to fiscal 2010, we should enter the year at about 23,000 barrels per day if the third party pipeline issues are resolved by then. So, we expect our fiscal 2010 volumes to be roughly flat with 2009 even with the capital budget of less than 100 million. The fiscal 2010 volumes could be significantly higher of course if the Cote de Mer and Ammazzo wells live up to their potential.

John already discussed the Cote de Mer, so let's look at the Ammazzo prospect. We have a 20% working interest in Ammazzo; McMoRan has drilled the well to more than 11,000 feet and set intermediate casing and is drilling ahead. After some initial delays resulting from commissioning issues with the new rig we're using, we've been able to make good progress. We would expect to have this well TDed by June or yearend which could be very meaningful to our reserve bookings.

Importantly you may not have to wait a long time to get news on this prospect since we will drill threesome secondary shallow objectives and then the Rob-L sand, our first big primary objective potentially this quarter.

Ammazzo is targeting the same sands McMoRan's had Flatrock and other big discoveries nearby. We are very enthusiastic about this prospect potential and our continued strategic alignment filling efforts with McMoRan. Those joint efforts include the ultra-deep Blackbeard prospect nearby. There is nothing to add to what McMoRan recently said on his conference call. Rest assured we are moving toward towards the future completion and testing size on the potentially gain changing discovery.

Now before wrapping up the call let me review the strength of our current hedge position. In the midst of falling commodity prices our risk management strategy remaining heavily hedged has proven to be one of company's biggest assets. As of last week we had a mark-to-market of approximately $153.5 million. Due to combination of swaps, put spreads and collars, we have hedged roughly 100% of our production through reminder of this fiscal year and about 60% for the fiscal year 2010.

As the market has remained volatile, we have opportunistically managed our positions based upon our current market buys. Going forward, we will continue to be well hedged and will look to adjust our portfolio as market improves in late 2009 and early 2010.

This wraps up the formal presentation today. Energy XXI continues to have significant near term growth opportunities that remain fully funded even with our strategic reduction in CapEx. We look forward to reporting back to you on our progress and success hopefully soon.

Operator let's go ahead and open it up for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And our first question will come from Neal Dingmann with Wonderland Security (ph) (sic) [Dahlman Rose].

Neal Dingmann - Dahlman Rose

Good morning guys.

Steven Weyel

Good morning Neal.

Neal Dingmann - Dahlman Rose

Say, John a natural question, what'd you seen I guess going forward, and how aggressive can you all be given your cash position as far as a acquisitions, and sounds like there's going to be fair amount of properties teed up out there, are you seeing that yet, are you're being presented a lot of properties yet; give us an idea of what you're seeing further in that area?

John Schiller, Jr.

Yeah, I think your thinking is right, Neal, if you're going to see that, I don't think you've seen a lot of that right now. I think you probably, second quarter's calendar year before you start seeing a lot of things happening along those lines. Obviously, we're looking at all those is one of the reasons for paying down our debts where we position to do something.

Neal Dingmann - Dahlman Rose

Got you. And what about, I guess, you're done with the service guys a long time in a lot of these cycles, how do you play it different now in this cycle again. I guess, obviously we're "to move some of these" projects are over, will you just sort of contract rigs on a rig-by-rig basis, maybe speak about that. And then number two; some of the services you're already using now, have you seen anything decrease as of yet or will that be on the next project?

John Schiller, Jr.

Yeah, on rigs themselves, we've pretty much done a rig-by-rig -- well-by-well contract. We had six month on our sleeves; we're through with that. The only commitment we have on our entire operated, at least, the only commitment we have is with the Rowan rig, Mississippi, and we're committed to one more well after Ammazzo there. And then, on the non-operated piece, Devon's got a contract to do repair work at Eugene Island 330 but we are not part of that contract. So, we've managed the rigs pretty good.

On the LOE side, we're doing what some of our other friend are doing. We're sending out letters and saying, hey guys, times are tough, we can find lot of people to work cheaper, so tell us what you want to do. And the responses have been pretty good. I mean, we've -- transportation, chemicals, things like that we're starting to see responses come in on reductions. Some of them are -- like yesterday, one of the guy that puts consultants on our rigs, lowered his rates back to 2006 rates. And that was on (inaudible), he just sent it out that, hey, we know what those guys want, so here's what we want to do to keep our guys working.

Neal Dingmann - Dahlman Rose

Okay. And, what are you seeing -- I saw in the update, I guess, when you go forward, how aggressive the operation will you be on some of the Gulf Coast properties on the gas that's operated, do you still going to go drilling with them, will you try to operate more of those, maybe a bit more color on just sort of the Gulf Coast properties?

John Schiller, Jr.

Yeah. I think, Neal, when you look at -- if commodities stay at this price other than the exploration we are committed to we're hunkering down and doing behind pipe re-completions, a few workovers and things like that. We are not looking to put any money to work in exploration onshore under that total shutdown model if you do not shut down, but spending less than 100 million CapEx. And some of that's driven by -- I don't think they are looking to drill even with -- particular with cash there (ph).

Neal Dingmann - Dahlman Rose

Got you. And then last question, anything new or is it too early to work as far as insurance for next year, have you got any indications, would you play that different now, I mean I'm sure costs will go up a bit, have you an interest for only the guys look at that?

John Schiller, Jr.

Oh yeah, we've looked at it really hard. It's quite fair to say costs are going to up. We are going to -- we're looking at everything that's out there in the entire spectrum is what -- is what I'll tell you from conventional insurance to some stuff at that side of the box. And we're going to get our assets. I'm sure that we're going to do in such a way that we fell like we haven't been late for doing it if you will.

Neal Dingmann - Dahlman Rose

Got you. Thanks, John. I appreciate.

John Schiller, Jr.

Okay.

Operator

And our next question will come from Duane Grubert from CRT Capital.

Duane Grubert - CRT Capital Group LLC

Yeah. The exploration program is pretty much working on its own pace. I would like it if you guys could just discuss a little bit more, what kind of forward schedule you can see about promoting or getting to that behind the pipe stuff -- some of the PD&P stuff. And, I was just wondering if you could characterize the size of your backlog of work overseas, is the environment right now where you have way more than you can fund or not, and whether you'd be looking to form into other people, if you didn't have much of a backlog.

John Schiller, Jr.

Yeah, a couple of things Duane. First off, just as you be broad base looked at things, your PDMs are obviously tied to when your PDP production goes off. And the account of sort of just kind of broad picture the company, your PDP productions have declining and somewhere plus or minus 5% of the 30% sort of decline rate.

So then you bring the PDMs on as those wells go off and that flattens you into the 15 to 20% sort of range. And then you need other production to help you there, some of which is your probables associated with your PDPs; they come in and flatten things out. And so that group of -- it's just kind of scheduled back behind when those wells go off. Now what we've seen and what we're starting to do and what we are going to do in this hunker-down period is, go back through and start really working over that work program inventory list. For instance we had no one that looked at East Cameron 330, 334; I am sure we did a couple of re-completions there this year in both of those constituted 10 million a day and 5 million a day appear to be virgin pressures, appear to be fault blocks that have never been drained and feel better (ph) that we made a Tcf of gas, so one would've assumed that we are drained.

They only follow those re-completions, they are still behind the pipeline damage, but we continue to identify things like that. For instance at South Tim, one of reason the volumes are up is we've identified 10 rig-less workovers, we thought we'd get about 1300 barrels a day out of those and the first two are giving us 1300 barrels a day.

So as we slowdown and take a focus of running the rigs and looking at our inventory of opportunities, those are the things that start popping on. So yeah I think we've got a descent inventory; I think we've going to continue to build that inventory and those are the things you do just about any price environment especially when a rig's not involved.

Duane Grubert - CRT Capital Group LLC

Okay, that was very helpful. And then on Cote De Mer, you guys talked about some modest pay zones that you've already encountered with the well. Whether you add significantly which we are all hope you do or not, what's the timing of getting a Cote De Mer on production?

John Schiller, Jr.

Production we expect rather to get along about six months.

Duane Grubert - CRT Capital Group LLC

Okay. Thank you very much.

Operator

And our next question will come from Jefferies, we'll hear from Evan Templeton.

Evan Templeton - Jefferies & Company

Hey thanks guys. Just a follow-up on Cote De Mer, can you just walk us through, I guess, with the primary target what that was, what you might kind of expect to see as you continue to finish that well up to total debt.

John Schiller, Jr.

Sure.

Evan Templeton - Jefferies & Company

If someone else has seen production at that horizon, just to give us a little bit more color so we can start the handicap additional success.

John Schiller, Jr.

Evan, I mean, I'll more or less say exactly where we are at. We drilled the massive sand somewhere in the neighborhood of 700 for the growth sand. We have an LWD across it, we do not have wire-line across anything but the upper piece of it. In there we saw gas, water, gas, water, gas, if that makes sense; with gas on the bottom and on the top. And so we've quoted the obvious pay in there, with a sense we drilled out about 60 per shale, we think, by -- from penetration rate and that's where we had our circulation problems which started almost a month ago. And we ended up with a kick and everything else. We have to find a way out of that; now we are back to drilling today.

We've got about 600 feet to drill through what we think our two or three more sands below that massive sand and obviously with the whole sand not trapping, we are looking at what reached our trap -- what we trap, and one of the things that obviously jumps to mind is that the sand is just so thick, you are just opposed or set against another sand across that fall. And we can build a story where that's happened on the edge of the trapping fall and why we are trapping gas within that hole (ph) and don't where we are.

And so what we want to see is recoveries other sands that won't be as thick and see if they load up and that's kind of where we are at right now.

Evan Templeton - Jefferies & Company

Okay. So when do you hope to have I guess in terms of a timeline next results on the well out?

John Schiller, Jr.

John Mann (ph) is in here. Let's have Kim (inaudible) taken the TD. Jim?

Unidentified Analyst

Yeah, we should -- here one of the things that's going to happen, and it won't drilled down 7 to 10 days; on this bedrock, we should have TD. Don't have -- perfect LWD, we want to get a high resolution Schlumberger log across it and then we are probably going to go back in there and look at pressure samples and things like that so that we know exactly what we are dealing with. And that's from a stent that we rot around the edge of maybe neither 15 or 20,000 palm tree and things like that plus some continuity on the reservoir would tell us a lot of the things that we can gather some more data. If the hole behaving itself, we'd like to have that, my guess is we got a 50-50 chance on some of that asset. And that's where we are at right now.

Evan Templeton - Jefferies & Company

Okay, perfect.

John Schiller, Jr.

Thank you.

Operator

And our next question will come from Richard Tullis with Capital One Southcoast.

Richard Tullis - Capital One Southcoast

Hi, good morning John.

John Schiller, Jr.

Good morning Richard.

Richard Tullis - Capital One Southcoast

Going back to Cote de Mer, sorry about that, I know initially you guys were talking about some gross potential there, even as big as potentially a half a tea; what are your thoughts now on the gross potential even if you find something in the lower 600 feet?

John Schiller, Jr.

The good news is where we're drilling; we get further and further of structure. So, if we log some pay, we still get some pretty good sized numbers in here. I won't say 500 Bs, but I will say, in excess of 100 Bs is still easily potential. And it's just relative to where we're seeing these sands versus the structure right now.

Richard Tullis - Capital One Southcoast

Okay. What's your -- the total cost in that well so far?

John Schiller, Jr.

Total cost today is -- we expect net of not including insurance reimbursement $50 million. So we are at about $165 million on a gross before insurance.

Richard Tullis - Capital One Southcoast

How much insurance proceed do you expect to get there?

John Schiller, Jr.

To date, we've gotten 9 million net. There are some claims still up in the air and some other things. So, we've got the potential to double that again, I think, on a net basis.

Richard Tullis - Capital One Southcoast

Okay. If you would, could you recap the production outlook, say, the rest of this year, or March through -- or January through '09, June '09, and then July '09 through to the end of the year?

John Schiller, Jr.

Yeah. I think for the quarter what you heard was pretty straightforward. We think we'll hit over 20,000 for this coming quarter.

Richard Tullis - Capital One Southcoast

Okay.

John Schiller, Jr.

And then we go out at the end of the year at probably 22, 23, it depends a lot right now on when we get the volumes up from the hurricane; Sea Robin's kind of been all over the place on that.

Richard Tullis - Capital One Southcoast

Okay. So, you said 22 to 23 you would exit your fiscal year?

John Schiller, Jr.

Yeah, I think it's somewhere right around there -- 22.

Richard Tullis - Capital One Southcoast

Okay.

John Schiller, Jr.

And then, we think, we're stayed relatively flat to that in 2010.

Richard Tullis - Capital One Southcoast

Okay.

John Schiller, Jr.

So as Steve alluded to when he talked; we have as around 20,000 for fiscal year '09. We're actually still showing uplift for '10; you don't do each capital.

Richard Tullis - Capital One Southcoast

Okay. How are things looking on the covenant's front?

John Schiller, Jr.

We're in good shape there, everything's fine. We don't -- there's no immediate concerns about anything. We continue to watch all that very carefully and we think we're in great shape.

Richard Tullis - Capital One Southcoast

Okay. And finally, I know you didn't have anything in your release about year-end pricing, I guess because of the fiscal year. If you had used yearend pricing, what would your reserves had looked like?

John Schiller, Jr.

Well, we did use year-end -- I am little confused -- I mean we used the quarter pricing for our ceiling test.

Richard Tullis - Capital One Southcoast

Yeah but for any negative reserve revisions, anything like that?

John Schiller, Jr.

Yeah. I guess, I'll give you the color, Richard. We are kind of unique in that, ours is about June 30th, so, with kind of an interim look. But if we had been at December 31st reporting, okay, we would have lost about 7% of our reserves due to pricing and about an incremental 2% we had to takeoff as of now because of hurricanes.

Richard Tullis - Capital One Southcoast

Okay. All right, very good, John. I appreciate it. Thank you.

John Schiller, Jr.

Thank you.

Operator

Our next question will come from Pritchard Capital Partners, we will hear from Steve Berman.

Stephen Berman - Pritchard Capital Partners, LLC

Yeah, good morning, guys. Just to clarify that some of you said on Richard's production question. Earlier, you'd said full fiscal year '09 production would be greater than 20,000 barrels a day. And then I think I just heard that the -- this quarter we're in now would be over 20, but earlier you'd said, January was 21,005 and you're currently at 21. So, can you just clarify the March quarter one more time?

John Schiller, Jr.

Yeah, March quarter, we expect to be above 21,000.

Stephen Berman - Pritchard Capital Partners, LLC

Above 21, okay.

John Schiller, Jr.

Right.

David West Griffin

I think we said for call fiscal year '09 with June 30th, we should be able to pull that average up to close to 20.

Stephen Berman - Pritchard Capital Partners, LLC

Got you.

David West Griffin

19 for the first half of the year.

Stephen Berman - Pritchard Capital Partners, LLC

And then a liquidity question on -- you'd said your mark-to-market gains are over 153 million in Europe, you are 100% hedged for the second half of fiscal '09 and I think you said 60% for fiscal 2010. With that as a background a lot of companies have a lot but several companies has been monetizing some of their hedges to improve their liquidity positions. Is that something on your minds at all?

John Schiller, Jr.

We look at that very hard. One of things I think if you go back there mark-to-market and see how much of that gain is in the next -- over the next year, we're going to get that money really quick and when you go and talk to these guys, the hair cut they want to give, give you a particular example, a large piece of that is that 3,000 barrels a day at any time on a put spread that's worth $25 a barrel to us right now.

We've haven't had an alter above 20 on that. So to give up 20% on something that we are going to have over the next when we don't absolutely have liquidity issues, it's kind of hard to do. So, we just keep rolling our cash at the bottom-line every month. But we're looking at some of the other positions, some out swaps and things like that so there's anything we can do that makes sense.

Stephen Berman - Pritchard Capital Partners, LLC

And on your higher volumes any thoughts on further repurchases there?

John Schiller, Jr.

We continue to look at all our options with regards to the bond.

Stephen Berman - Pritchard Capital Partners, LLC

But you have -- you -- there's nothing restricting you here from find always some more of those back?

John Schiller, Jr.

Not at all.

Stephen Berman - Pritchard Capital Partners, LLC

Okay. That's it from me. Thanks.

John Schiller, Jr.

All right.

Operator

And our next question will come from Michael O'Brien with Collins Stewart.

Michael O'Brien - Collins Stewart

Morning guys.

John Schiller, Jr.

Morning Michael.

David West Griffin

Good morning Michael.

Michael O'Brien - Collins Stewart

Yeah, it feels like morning. But just a very quick question. Why don't you just expand a bit more on what the covenants actually are?

Steven Weyel

Sure. We have two covenants in our corporate revolver, we have a total debt to EBITDA covenant as well as a EBITDA to interest coverage covenant. Those are the two principal ones that are the main driver. We also have a quick ratio covenant: current assets to current liabilities plus included in the current assets portion you get to include the un-burn portion of your revolver and a couple of other add backs. But those are the three covenants. But again the only two that really matter in there are the -- is the total debt to EBITDA and the EBITDA to interest coverage.

David West Griffin

And the EBITDA, Michael, it's a trailing 12 months EBITDA.

Michael O'Brien - Collins Stewart

Fine. A more fixed term of a loan that don't actually decrease or increase as you go along.

Steven Weyel

That's right, it's just a fixed covenant.

Michael O'Brien - Collins Stewart

Fine.

Steven Weyel

The EBITDA -- the debt to EBITDA's 3.5 times and then the other one's 3.0 times in there (ph).

Michael O'Brien - Collins Stewart

Cheers guys.

John Schiller, Jr.

Thanks Michael.

Operator

And our next question will come from Kevin Malone with RBS (ph).

Unidentified Analyst

Hi, good morning guys. Can you hear me?

John Schiller, Jr.

Yeah.

David West Griffin

Yeah.

John Schiller, Jr.

Morning Kevin.

Unidentified Analyst

Just a couple of clean-up questions. First of all for 2008 you said and I guess for 2009 it looks like you are going to do 100 million of CapEx for the last months and for all 2009?

John Schiller, Jr.

Yeah, we didn't clean that up. We will clean that up for you. The second half -- the first half of calendar year '09 and second half of our fiscal year '09 --

Unidentified Analyst

I hear it, yes.

John Schiller, Jr.

We should spend less -- around about $100 million for the -- in other words the next 6 months including January, we already went through.

Unidentified Analyst

Right, Okay.

John Schiller, Jr.

Then when you jump to the next year -- fiscal year 2010 for us, July 1st of this year through June 30th the next year, CapEx should run about 100 million for that whole time frame.

Unidentified Analyst

Okay. And that's net -- is that net of insurance recoveries or is that gross?

John Schiller, Jr.

That is net.

Unidentified Analyst

Okay. And then just lastly on the reserves. You said it was 7% of reserves for price revisions -- is that also the 630 reserve report or that's what you offer your internal 12/31 numbers?

John Schiller, Jr.

About the 630 reserve report.

Unidentified Analyst

And what would that do to your depreciation rate going forward? Do you have a ballpark of how far that's going to drop?

David West Griffin

Yeah. It's $26.72 is the DD&A rate going forward without any -- assuming everything stays right where it is right now.

Unidentified Analyst

Okay. Good job in tough times. Thanks a lot.

John Schiller, Jr.

Thanks.

Operator

And from JMG Capital our next question will come from Jeff Miller.

Jeff Miller - JMG Capital Management, LLC

Thanks. My question has been answered.

John Schiller, Jr.

Good morning, Jeff. Pricing up (ph).

Jeff Miller - JMG Capital Management, LLC

Good morning.

Operator

Thank you, Mr. Miller. Our next question will come from Sharath Reddy with Redwood Capital.

Sharath Reddy - Redwood Capital

Hey guy, my questions has been answered. Thanks very much.

John Schiller, Jr.

All right.

Operator

And our next question will come from Biju Perincheril with Jefferies.

Biju Perincheril - Jefferies & Company

Hi, guys. Good morning. A couple of quick questions. Your second half '09 and 2010 CapEx, roughly 1% of that is for the sort of exploitation projects that you described versus exploration?

John Schiller, Jr.

20% is exploration.

Biju Perincheril - Jefferies & Company

Okay. And that's versus about half in the first half of '08?

John Schiller, Jr.

The first half of '09 was about half exploration.

Biju Perincheril - Jefferies & Company

Yeah.

John Schiller, Jr.

Right.

Biju Perincheril - Jefferies & Company

Okay. And then one more question on Cot de Mer what would be the incremental cost from here for the completion of that well, and can you give that number assuming how you find more success, and as you told further and what you found so far?

John Schiller, Jr.

Yeah, on the cost side, we're looking at about $5 million net going forward for our share that's complete. And there's always a second half by the -- when we're looking at each other in here.

I was going to stay awhile (ph) is then 5 million more than that you find more pay is it about the same?

John Schiller, Jr.

Yeah, I mean, we offer 15,000 -- found 3-hours a string of tubing (ph).

Biju Perincheril - Jefferies & Company

Okay.

John Schiller, Jr.

One side lock and lay about -- how many miles slow on? About 9.5 of fur line.

Biju Perincheril - Jefferies & Company

Okay.

John Schiller, Jr.

And facilities. So that -- also those numbers are the same whether 10 Bs or 100 Bs for this completion.

Biju Perincheril - Jefferies & Company

Got it. And what -- from what you found so far, what kind of rate would you expect from one well.

John Schiller, Jr.

I think in his zone we have so far, 15 to 20 million (ph) a day is reasonable rate.

Biju Perincheril - Jefferies & Company

Okay. And that will -- you will able to drain that one well?

John Schiller, Jr.

If it's pressure drive, yes, which is what we would think. We'll get large amount from one well.

Biju Perincheril - Jefferies & Company

Got it. Okay. Thanks. That's all I had.

Operator

And our next question will come from Bruce Rococks with Cuberlane Associates (ph).

Unidentified Analyst

Good morning, John. I just wanted to clarify on the reserve comment, are you talking about reserve units, the 7% differential between yearend and -- or if I could just rephrase the question, after the ceiling test write-down, what are your reserve units mix between oil and gas and PDP?

John Schiller, Jr.

I didn't really go into all that, Bruce, and I'm planning to show how they run for me. But what I was trying to say is when you look at 51.5 million barrel reserves.

Steven Weyel

As of 6/30.

John Schiller, Jr.

As of 6/30, and you look at the impact of prices in the hurricanes; we loose 9% of those reserves.

Unidentified Analyst

Okay. That's good enough, John. That's helpful. And, I think all of my other questions indeed have been answered. So, thanks very much.

John Schiller, Jr.

All right.

Operator

Our next question will come from David Ambler with Global Credit Advisers.

David Ambler - Global Credit Advisers

All right. Just one quick question; on 26th the comment the Miller point focusing on reducing debt, repaying more than 100 million in fiscal year 2010, could you just give me a little bit more color on the underlying assumptions on kind of how you meet that level of 100 million in 2010?

John Schiller, Jr.

Yeah. I mean, that's based on our current strip prices tag plus our hedges, it's the production numbers that we talked about in the low 20s.

Unidentified Analyst

Okay.

John Schiller, Jr.

We kept capital below 100 million -- we got interest payments of about 75 million.

Unidentified Analyst

And your CapEx of 100 million or so that you other assumptions, I guess, right?

David West Griffin

Exactly, even less than 100 million but --

Unidentified Analyst

Okay. I just wanted to -- thanks a lot, just wanted to confirm that.

David West Griffin

Okay. No problem.

Operator

Our next question will come from W.H. Ireland, we will hear from Gaius King.

Gaius King - W.H. Ireland

Gaius, but that's close enough. Look just a couple of questions, I just want to concentrate on the $0.07 loss due to pricing and the 2% due to hurricane. I am looking at your balance sheet your cost mix or accounting. Now I noticed that there is actually a 21% decrease, 9% is what you've previously stated. Am I right to assume that the 12% is due to production, the 12% difference?

John Schiller, Jr.

No. You're trying to draw a correlation that's not there.

Gaius King - W.H. Ireland

Okay. So [multiple speakers] you should choose a price costing then? And you've got there in the note that it's cost mix sort of accounting obviously acquisition or drilling or what not. I'm just wondering the 12% differential between the two numbers in June 30, and December 31st.

John Schiller, Jr.

That going to bunch your challenge, you can't get it that way.

Gaius King - W.H. Ireland

Right.

John Schiller, Jr.

Once we get, I mean, you got you pre-pending assets that you're dealing with and then it's how many dollars per barrel you have on those versus what the PD of the properties are. So there's not really a direct correlation between reserves some of -- some of what you write-off could be minimum dollars and some could be a big part of the total write-down, it just depends.

Gaius King - W.H. Ireland

Okay. So, it's not strictly cosmic of accounting. There is some sort of revision due to economic outlook?

John Schiller, Jr.

Absolutely.

David West Griffin

Yes.

John Schiller, Jr.

Yeah.

Gaius King - W.H. Ireland

Okay. So, that leads to my second question. Just the effect of hedges which going forward, this question in two parts, the beneficial component of hedging I suppose effectively runs out within the year or two. How's that going to affect your gas properties and I guess the way that your account for them. And the second part is in if a way 10 onwards, you guys are expecting the low price to increase, where are you strategically placing yourselves if oil prices and global economy starts increasing in a year or so?

David West Griffin

If you look our hedge slides I think what you will see is we've got average prices just running through our hedge position as right now, Okay. If you take the market impact on our volumes from where -- what we don't have hedged --

Gaius King - W.H. Ireland

Yes.

David West Griffin

-- at the current strip and then you look at our hedge position for fiscal '10 we get almost $68 a barrel for our crude; fiscal '11, 65; on the gas side we are right around 7.50 and 7.40 an Mcf. So, we're pretty well positioned there relative to the current strip across all our assets.

Gaius King - W.H. Ireland

Right.

David West Griffin

As part of your question, we look harder at all the time. Our bias is what we are those oil prices. So, anything we do in that here is we are trying maintain upside and that's kind of the strategy we apply. But if you looked at we're pretty well hedged in '09 and '10 for all of our gas currently that we can. '11 we got a little room to put on some gas, we got a little in '10 and '11 for some more. But that's why it's always important where we're looking right now at all of our -- now we just went through a strategic plan with our board and looking at our volumes and our forecast because those have direct impact on how much hedging when we have on our bank covenants.

Gaius King - W.H. Ireland

Sure. Thank you very much sir.

David West Griffin

You're welcome

Operator

And our next question will come from Doug Loschil from Slogan (ph).

Unidentified Analyst

Most of my questions have been answered. Just curious why the cash has gone down. It looks like about 24 million from end of December to Feb. 6th, and what you expect cash levels to be at the end of fiscal 2010?

David West Griffin

Okay, the --

John Schiller, Jr.

Good morning Doug.

David West Griffin

Good morning Doug.

Steven Weyel

Morning Doug.

David West Griffin

The cash levels have gone down for a couple of different reasons. One is we have been rapidly decelerating the activity on the capital side but commodity prices have fallen faster then our abilities to slow things down on the capital side. The other thing is that we had obviously hurricane repairs, so we have a short-term timing difference between -- we have spend the money to do the repairs and then we seek imbursement.

So, one of things that affects us is that the buildup in account receivable with the insurance company and this is like previous environments that will continue to build a little bit here. The -- but from a cash flow standpoint, if you look at sort of the fundamental elements of it, your EBITDA, interest expense less your CapEx while the first half of the year we outspent those three items, the second half of the year looks like will be to the positive side associated with it. That being said we've got insurance and some working capital issues that will affect us.

Unidentified Analyst

Okay, thank you.

John Schiller, Jr.

Thanks guys.

Operator

And just --

John Schiller, Jr.

Go ahead.

Operator

(Operator Instructions).

John Schiller, Jr.

And I think I will just wrap it up right here. Appreciate everybody being on the call today. It's tough times where you've got a management team that's prepared to handle it. We've all been there before, we know what we need to do to make things right and we remain 100% focused on creating value for our shareholders. Thanks for joining us this morning.

Operator

That does conclude our teleconference for today. We like to thank you everyone for your participation and have a wonderful day.

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Source: Energy XXI (Bermuda) F2Q09 (Qtr End 12/31/08) Earnings Call Transcript
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