Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Stewart Lawrence – VP, IR and Communications

John D, Schiller Jr. - Chairman of the Board, Chief Executive Officer

David West Griffin - Chief Financial Officer

Steve Weyel – President and Chief Operating Officer

Steve Nelson - Vice President - Drilling and Production

Analysts

Duane Grubert – CRT Capital Group LLC

Nicholas Pope - Dahlman Rose

Michael Bodino - Madison Williams

Eric Anderson - Hartford Financial

Andrew Coleman - UBS

Evan Templeton – Jefferies & Co

Joan Lappin - Gramercy Capital

Tom Romero - Capital Research Partners

Biju Z. Perincheril - Jefferies and Co.

Richard Tullis - Capital One Southcoast

Ron Mills - Johnson Rice

Stephen Berman - Pritchard Capital Partners

Presentation

Energy XXI Ltd. (EXXI) F2Q10 (Qtr End 12/31/09) Earnings Call January 21, 2010 10:00 AM ET

Operator

Good day, ladies and gentlemen. At this time I'd like to welcome everyone to the Energy XXI second quarter 2010 earnings conference call. During the presentation, all participants will be in a listen-only mode. A question-and-answer session will follow the company’s formal remarks. (Operator instructions) Today’s conference call is being recorded. And now I would like to turn the call over to Stewart Lawrence, Vice President of Investor Relations. Please go ahead, sir.

Stewart Lawrence

Thank you, Carla. Welcome to the call today, everybody. Presenting today, we have John Schiller, Chairman and CEO; Steve Weyel, President and Chief Operating Officer; and West Griffin, Chief Financial Officer, who will be available, of course, 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 -- last night and in our public filings. We disclaim any obligation to update these forward-looking statements. While the company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance.

Our drilling schedules, capital plans and other factors may cause our results to differ materially. I urge you to read our 10-K and our latest 10-Q to become better familiar with these risks and our company.

Now I'll turn the call over to John.

John Schiller

Thanks, Stewart. Welcome, everyone. The past four or five months have been action packed with non-stop activity. Beyond a doubt, it's been the most exciting period of my career and we firmly believe that the fun is just beginning. We got the ball rolling on September 4th when we announced our fiscal year-end results and proposed our bond exchange. The stock market roughly doubled in price, the stock roughly trebled in price in a couple of days.

Five weeks later we successfully completed the data exchange, cutting the base amount of our bonds outstanding by $69 million, in addition to completing the private placement of new notes and equities using the proceeds to pay down part of our revolver. By that point our stock was about triple the September first price. Less than two weeks later, on November 23rd, we announced the MitEnergy Acquisition, and our stock continued to climb. We announced the equity in offerings to pay for the acquisition, conducted a brief but very successful road show, priced the deal and closed the acquisition all within a 30-day time period. By the time we exercised our common stock over allotment the stock was back near a 52 week high.

Then things got really fun, January 11th, we and our partners announced Davy Jones as a major discovery with 135 net feet of pay sand. On January 20th we reported another 65 net feet of pay, taking our total to 200 feet in the Davy Jones well. I can assure you we believe there is more good news to come associated with this project.

We've come a long way but that's been off a very depressed base. In our minds and this is strongly supported by our analyst coverage, the current stock price hasn't even reached a net asset value of our proved reserves, let alone the upside of our expanded property portfolio. So Davy Jones, the Blackbeard discovery, and the rest of our ultra deep exploration program was essentially free.

We understand this trend won't ever go straight up, there will be profit taken in retrenchment. But one result of the lagging share price response is that we will likely remain on the sidelines in the acquisition market at least for anything sizeable enough to require a large equity component. It would be pretty close to impossible for us to find any better place to invest our capital than our own ultra deep development and our core property exploitation efforts.

It's important to note that we see no scenario in which we would need to sell equities to fund Davy Jones development or to sell down any of our interests in the ultra deep play to be able to stay in the game. This is a concern we hear daily which is why we came up with the following slide last month. Don’t get too wrapped up in the details of the slide, it's for illustration only, but we show the assumptions which we intend to be very conservative on all accounts.

The only point we are trying to make is that the economics is superb even in a conservative case and that we would not expect to ever be out of pocket by a tremendous amount of capital, since the world should come online and begin spinning off significant cash flow to fund the program under a relatively short period of time. This slide addresses the development of Davy Jones only.

We also tend to remain active exploring the ultra-deep. Altogether we expect our share in the ultra-deep program to be in the $50 million to $75 million range annually; that is for Davy Jones development plus one additional rig drill and exploration prospects, full-time.

We also expect to spend in the neighborhood of $150 million a year on our basic exploitation program on fields like South Timbalier 21, Main Pass 61 and 72 and South Pass 49, including some normal exploration efforts.

If you add in our annual interest expense of about $85 million, our capital requirements and cash requirements total around $300 million a year. Analyst cash flow estimates all exceed that level just from our existing portfolio, let alone the cash that we will generate from Davy Jones within the next couple of years. Bottom line, we expect to fully fund both the ultra-deep effort and our normal capital program with existing cash flows and still have free cash flow left to reduce our net debt levels. Maybe that changes if we will have a rapid series of giant ultra-deep discoveries that we need to develop, but that's a problem we would all love to face.

Just a comment before I turn over to West for the financials and Steve for the operations overview, trying to sort out the results from December quarter may take more effort than it's worth. All the big events that we covered have made Energy XXI a much different company today than it was just a couple of months ago, and many of those events created one time impact that skewed the reported results, everything from reported volumes to overhead costs to cash flows. We'll touch on some of the bigger items and be ready to walk you through you models off-line if you're compelled to clear up every detail.

Here is the real take-away for the quarter; the debt exchange that we completed in November was a more important event than most people realize, because it got the ball rolling on cleaning up the balance sheet. Without it, we would not have been in position to do the MitEnergy deal, which we believe was an acquisition of a lifetime. And that acquisition with the significant free cash flows that the property could generate helped to insure that we would stay in the game chasing the ultra-deep exploration program and we firmly believe those efforts have delivered significant discovery with Davy Jones.

We believe this is just the start, as my good friend Jim Bob says, stay tuned. Now, let's turn it over to West to review the financials.

West Griffin

Thanks, John. Okay, let's clarify some of the quarter’s notable items. Our daily production volumes recovered nicely in the quarter averaging nearly 21,000 barrels a day, that's about 2.000 barrels a day higher than we had indicated last quarter, which you can attribute to volumes from the acquisition of the MitEnergy property from December. As we've highlighted, the acquired properties are primarily oil, so our production became even more oily in the quarter at nearly 68%. This helped drive our revenue for BOE to a recent high of almost $65 per barrel.

On the expense side a couple of items stand out. Total LOE or lifting costs were higher, but that was caused by both an increase in our percentage of oil, oil has higher lifting costs than gas, as well as the requirement of Energy XXI to pick up Mit's share of their insurance cost until closing. With our taking over the assets in December, we should see the insurance portion of the LOE decline to the $2.75 per BOE range through June, at which point we will renew our insurance and we will have a new level of insurance.

G&A was up largely due to the transaction cost related to the bond exchange in Mit acquisition, as well as stock based compensation. We expensed cost related to the bond exchange of Mit acquisition so the total dollar amount of G&A is higher by about $4 million. In addition, the stock based compensation cost rose. For example, the quadrupling of the share price requires us to true up the accrual stock base bonus awards. I'm guessing we wouldn't mind seeing a repeat of that expense soon.

Looking forward to the March quarter, even with further stock price appreciation realized today, we'd expect G&A to decline to less than about $10 million. Other items worth mentioning; in the income statement, we had about $26.7 million pretax gain related to the 10% notes we had repurchased on the open market at a discount some time back, but hadn't officially retired until November.

On the cash flow statement, you'll note that the accounts receivable went up nearly $54 million. This was largely due to the Mit transaction, this should decline some as we start collecting revenues pursuant to our normal payment terms. In addition, you'll see that asset retirement obligations reduced cash flow by $36.2 million in the quarter. Essentially, we had a lot of hurricane repair bills come due, remember though we had collective insurance proceeds for these expenses recently, including $45 million in the December quarter.

The last cash flow item of note, we went back to the more normal position of holding a modest cash position using a $119 million of cash during the quarter to reduce the amount borrowed against the revolver.

On the topic of our long-term debt, at December 31, our $199 million revolver has 149 million drawn and we had 23 million of cash. There were $277 million of the 10% notes, $338 million of the new second lien notes, and $6 million dollars of other debt. That put total net long-term debt at $747 million in terms of the principal amount. Another note regarding revolver, we received commitments to extend the maturity of our revolver to February 2013 and to increase the borrowing base to $350 million, and we anticipate closing the amendment in the next week or so on completing the final documentation.

We took this opportunity to reconstitute our bank group, we're very pleased to have two new banks come in to the bank group. Following the MitEnergy deal and the equity raises, our cash flows and our balance sheet are both in much stronger positions and our liquidity should cover any foreseeable operational needs.

Now, I'll turn it over to Steve for the operations discussion.

Steve Weyel

Thanks, West. Production in the 2nd quarter averaged 20,900 barrels per day, up from the 15,500 barrels per day in the first quarter. We updated you in the last earnings call that we drilled and completed three new wells in our Main Pass 61 field, wells came online in late October at a combined rate of 2,200 barrels per day net and they are currently producing 3,500 barrels per day net with the additional interest we've picked up in the MitEnergy Acquisition.

As a company, we are currently producing about 26,000 barrels per day. We are curtailed on our outside operated Fastball well by about 1,000 barrels per day due to a leak and subsequent shut-down of the Chevron oil sales line. We are being told that repairs are expected to be completed by April 1st, our January production averaged about 23,000 barrels per day, reduced by the Fastball curtailment plus an extended shut-in at Main Pass, due to a Corps of Engineers dredging work near our oil sales line.

Elsewhere we're finally seeing real progress in return production that has been offline since Hurricane Ike. Our Eugene Island 280 well and our East Cameron 334 A and E platforms were returned to production in mid-January at 1,075 barrels per day net. All that remain is our East Cameron 334 B platform and our South Pass 49 platform to be returned to production by mid February, adding another 3,000 barrels per day net. With everything up and running, we should have a near-term capacity rate of about 30,000 barrels per day.

So where do we go from here? In the current budget, we have very little additional development activity planned through June, that's just a function of front loading the capital program, but we continue to consider incremental opportunities that deliver high cash flow in the near term. We have complied a drill ready back log of high graded prospects, we're opportunity long and we continue to increment our acreage positions around our cores assets. This inventory includes our increased interest in the Main Pass and South Pass areas, resulting from the MitEnergy Acquisition, and we should highlight that Mit assets were digested seamlessly as expected.

Now a few words about our risk management program; the next two slides show the current hedge position for natural gas and oil. If you do the math, you will see that we remain well hedged for the current fiscal year ending June 2010. We continue to actively manage our hedging program and specifically will consider adding to our positions to protect new volumes coming online from the capital program.

Now, let's turn it back over to John for the closing.

John Schiller

Thanks, Steve. It's difficult to put in words just how excited we are about the future of Energy XXI, we have a major discovery that may be just the tip of the iceberg, as well as an expanded production portfolio capable of generating significant amounts of free cash flow. As I said last quarter, the dominoes are prettily [ph] falling in place for us and we're excited about the company's future.

Now let's open up the lines for questions, operator.

Question And Answer Session

Operator

Thank you. (Operators Instructions) And we will take Duane Grubert with CRT capital.

Duane Grubert – CRT Capital

In your written release this morning it was mentioned that you guys successfully cored the Davy Jones, can you tell us a little bit about that? Did you get a core to surface that you will actually be able to use in the lab or did it fall apart? What can you tell us about the core?

John Schiller

We actually recovered 25 out of the 30 feet we attempted, unfortunately majority of it was shale and siltstone or the rattier looking sands and we're still moving forward on the analysis on the sandy part of it to see. And we are kind of early on, we've cut it and slabbed it, and we have identified the plug. But we're probably still two to three weeks away from actually getting permeability property [ph] data and stuff like that, Dwain

Duane Grubert – CRT Capital Group

Okay, on the idea of the slide that you guys had put out, with the detail on well costs and stuff, you reference an IP of 100 million a day which is not that unusual of a rate worldwide, but it is kind of unusual in the Gulf of Mexico. Can you just give us a little operational color on concerns about tubular erosion or what kind of things do you have to watch out for with big rates like that?

John Schiller

We got a lot of reservoir pressure. So we expect really to generate a fair amount of production off the reservoir itself. The limits are going to be some of the things you referred to, it’s going to be erosional velocities, it's going to be dependent on what size tubing we're able to get in the hole, what our pressure drops are, what our liquids are. So a lot of that is going to be a little hard to tell. What I would tell you is we think 100 million is a good average guess. I think you'll see a reservoir like this, these reservoir sands that we have, as we do the development, you'll see us work at getting bigger and bigger pipe programs that will let us run larger and larger tubing. And with that, you'll have some rates that'll be even in excess of anything we're showing here on these things, on the current economic slides.

Duane Grubert – CRT Capital Group

And then going back to the core, my limited understanding is that you would get some core data, you'd be able to say whether or not the best part of the sand or not, you'd be able to correlate, log against where the core came from and be able to have both a physical measurement of porosity, a physical measurement of permeability. Would that in general be enough data to get a third party auditor to give you at least probable reserves with all the other data you’ve got, independent of a flow test?

John D. Schiller Jr.

You’re limited data is dead on. To start with, of course, you know exactly what you’re talking about there. But I think it’s going to come down to – we had our first meeting with Nathan (ph) yesterday. McMoRan guys are meeting with Ryder Scott, their reserve guys.

There is a four point test of what you need to achieve, which Tom remind me is, seismic we have, log data we have, cores and fluid samples. So what we’re planning to do out there, and I think we mentioned it. But we’re drilling ahead right now. We’re drilling ahead at a decent rate. We made over 100 feet last night, closer to 150 feet for the last 24 hours. We’ll probably drill this thing around 29,000 feet, make another suite of log runs.

And then we’re going to bring – we should have the Schlumberger RFT tool which will allow us to obtain multiple pressures and one sample, per run. Now the pressures will hopefully allow us to do some things like identify gradients within the reservoirs, which give us an indication of what kind of liquids we’re dealing with. We really don’t expect the dry gas but the question is how much liquid condensate do we have with the gas. And we’ll also be able to get some indications of permeability off that.

I think when you put all that together we think we’re going to be in a position to, at a minimum, get some probable reserves. But it’s a little early. Let us see what data we get and then we’ll get back to you guys. And I would hope that when we do our investor conference March 4th up in New York, we’re in position to go into a lot more detail on this type of stuff.

Duane Grubert – CRT Capital Group

That’s great. Thank you very much.

Operator

And now we’ll hear from Nicholas Pope with Dahlman Rose.

Nicholas Pope - Dahlman Rose

Quick question, just in regards to David Jones. In terms of running a production test, I know it sounds like there’s probably a long lead time on certain pieces of equipment required for that production test. What are you all viewing as, I guess, as you see the size of this thing in terms of possibly accelerating it, maybe borrowing equipment, is there that kind of potential to kind of help try to move this thing, see it quicker?

John D. Schiller Jr.

Nick, we can play a lot of theory games right now. We have as Jim-Bob referred to it, our fast track or Indy 500 team of the company is all moving forward, all geared towards designing the equipment that’ll handle all the way up to the Blackbeard type well at 30,000 PSI.

What we really need on this well is what I just talked to about with Dwayne. We got to see our pressures and our gradients to give us some sense of – and get a fluid sample. Once we know that, we can quit playing the theory game and making educated guesses, which is what we are currently doing, and know exactly what kind of pressure is expected to surface and what we have to design around. And once we see that kind of data, we can get a long way down the road in terms of giving you a good time estimate.

Nicholas Pope - Dahlman Rose

Okay. That’s great. And then, there’s a lot of talk about the permeability of this well. I mean, have you, just in your experience, John, have you ever seen a well that has the porosity that it sounds like you’ll have without the permeability?

John D. Schiller Jr.

Yeah, I think Nick, when Jim Bob answered on his call, he went into a lengthy description of how clean the resistivities are and what that means about shale. I think more than anything that’s your best indicator of permeability. We have tools that investigate anywhere from 10 inches into the formation to 10 feet into the formation, when you’re getting your resistibility. And we’re seeing a nice spread on those tools which indicate that we’re sifting the signal (ph) out through the fluid in the rock up to 10 feet out. And you don’t see that kind of response when you have tight rock. They overlay one another. So when you get separation there, that’s a good example. The big booming resistivities indicate nice clean sand. And yeah, we couple all that with our porosity data, then you feel pretty good about your permeabilities.

And one other thing, Nick, I forgot to answer you and Dwayne. When we talk about test rates, I will caution everybody that because we reentered this well bore and because of the size of the pipe we’re going to run on bottom, which will be a five inch casing, we may not hit some big huge rate on this well. We’ll probably be somewhat more limited here then we will be on the other design wells,. just because of the size tubing we’ll be able to get into the hole on this well bore.

Nicholas Pope - Dahlman Rose

That’s great. And then, do you all think you’re going to get to the Tuscaloosa or do you all think you might case this well before – just to protect some of this well before you get that deep? Do you all have an indication that you all in the Tuscaloosa yet?

John D. Schiller Jr.

One never says never. But with what I think we’re going to see between here and 29,000 with some more sand and hopefully more pay, I think when you got close to 5,500 foot of open hole, it’s going to be time to run some pipe. And we’ll get to Tuscaloosa as we move up depth where it gets a little bit easier to get to.

Nicholas Pope - Dahlman Rose

All right. Sounds good. And then just real quick on the financial side, West, I think you made a comment on the stock based comp, as part of the G&A for the fourth quarter. Did you give the actual number of how much of the G&A was actually non – I didn’t see that in the release, I don’t know if I missed it, the non-cash portion of that?

West Griffin

No, we didn’t disclose that. I can –

John D. Schiller Jr.

7.5 is non cash right now, just accruals (ph).

Nicholas Pope - Dahlman Rose

That’s all I had then.

Operator

And now we’ll hear from Madison Williams, Michael Bodino.

Michael Bodino - Madison Williams

Thank you. Good morning, guys. Just a couple of follow up questions on mundane things like production. The ramp up and timing of these wells, can you give us a little bit better guidance relative to kind of how things are going to evolve Q3 and Q4 of your fiscal year in terms of production?

John D. Schiller Jr.

Mike, I would say that in this quarter, we’re talking we’re at 23 for the first quarter. We think assuming, like we talked about, at Fastball and some of those things where we continue to be dependent on Chevron to repair additional pipelines, if things work right, we should probably see 25 this quarter and be pushing 30 next quarter, the last quarter.

Michael Bodino - Madison Williams

Okay. And following up, on a couple of the guys other questions regarding Davy Jones, particularly on the slides, I mean, you’d indicated that possible first production in 2011, is that fiscal or calendar? And do you still feel that that’s a comfortable timeline for first production of Davy Jones?

John D. Schiller Jr.

Again, on that slide, we’re just trying to give you some sense of how negative we go in terms of cash flow demands and all. It is a calendar year slide, it’s not a fiscal year side. So it’s starting January 2010. And plus or minus six months we feel pretty good about it. So we – some time in 2011 getting production definitely is where we think we’ll be.

Michael Bodino - Madison Williams

Okay. And you think by the time you reach first production, assuming that all the data, all the flow tests, everything comes out as planned, when you initially start production you think it’s going to two, three wells, or is it going to be more of a one or two wells at the time you initiate production out there?

John D. Schiller Jr.

Mike, if you remember, we’re in 20 feet of water. Straight holes are going to be imperative to drilling and developing these fields. Part of our logging issues we think – we’ve got a 14 degree turn in this well at about 25,000. And that tends to create problems with wireline logs, which is what we really want to be able to do, that the tools that we’re using that are wireline rated are made to get in the hole log well and get out. And we’ve got to run them on drill pipes, takes a lot longer to do that. And that’s why you run some risks of temperature impacting your tools.

So that said, we’re still sitting in 20 feet of water, we’ll drill basically caisson wells, set platforms around those wells and have a central facility in addition to that. So I would expect to start bringing on the first well as we complete it. It won’t be like you do two or three and hook them up. You should be able to hook each well up as you drill and complete.

Michael Bodino - Madison Williams

But there’s not really any thought of bringing on production on the current well?

John D. Schiller Jr.

Yeah. That’s what I’m saying. As soon as we get it completed – it depends on whether we do a test to test or test at the completion. And that’s what we don’t know yet. I mean, it’s going to depend on what the pressure is. There’s scenarios where the pressure is greater than 20,000. Maybe we still are able to get a test. But it’s not something we can leave on that well head. So we circulate back around and kill the well. Or if it’s below 20,000 then we may be testing it and actually preparing to go to production fairly soon thereafter.

Just a little early to tell you all that. But in general, as we drill a well, we will drill and bring it on line. We won’t be waiting long period of time for two or three wells.

Steven A. Weyel

And Mike, we’ve actually, McMoRan already made arrangements for this first well to work with an existing production facility in the Gulf.

Michael Bodino - Madison Williams

Okay. So, I mean, it’s really – that 2011 is just put out there, just put out there. Or your hope is that – as I was looking at modeling it, by the time you had first product, you’ll potentially be down on the next well. And we have multiple wells coming on at once. But it’s really just a function of getting things equipped and online.

John D. Schiller Jr.

Yeah. And those two wells could come on in similar periods of time. But it’s just – what we did on those economics, Michael, is we just drew the most conservative capital numbers out there. What we thought was a middle of the road rate. We haven’t really fine tuned it in terms of the recompletion to bring it on different zones and things like that. We just threw all the capital out against it. So you’ll see it continue to – probably the economics getting better as we fine tune and know more about what we’re doing with it.

Michael Bodino - Madison Williams

Okay. And my last question. Given for the proof of the geologic model, how many more prospects does Energy XXI have interest in? And then, kind of, what are the thoughts of layering in some exploration over the next couple wells and targeting some of those prospects?

Steven A. Weyel

The general group is 10 –to 12. Like we’ve also said, prospects, we’ve identified a couple of more that are in very, very early stages. I think what you’ll see as we – we talked about over the next year, one rig drilling development, another rig drilling exploration. Depending on success, that could go to three rigs in multiple ways. Two rigs doing development and one rig exploration or one rig development and two rig exploration. Just depending on some lease timing and things like that.

Michael Bodino - Madison Williams

And your interest is pretty consistent overall those prospects?

Steven A. Weyel

The consistent part is the 45-35-20 split between us playing PXP and McMoRan. But it all depends on what interest McMoRan has originally, if we acquired new leases as we have been on some of the prospects, and that’s our interest.

I think as you have success you may see some parties that in the past would farm out to us may actually participate. And most of these structures are going to be very similar to the Davy Jones, where your drilling unit is basically four MMS blocks or over 20,000 acres in the unit.

And so we may control three of those blocks with somebody else on the fourth block decides to participate, that kind of knocks us all down 25%.

Michael Bodino - Madison Williams

All right. Very good. And congratulations on the quarter guys. And look forward to the next quarter with MitEnergy in there for the entire duration.

John D. Schiller Jr.

With you too, Michael. Thanks.

Operator

And now we’ll open the floor up to Eric Anderson with Hartford Financial.

Eric Anderson - Hartford Financial

Your statement about the coring, was that done at below 28,600? In other words, were the last bit of logging that you had done, did you core after that?

John D. Schiller Jr.

Yeah. That’s correct. We had drilled the well to like 28,603. And that’s where we did all our logging. And then we went back in and cored the last 30 feet.

Eric Anderson - Hartford Financial

Did that coring take a couple of days just to get those 30 feet?

John D. Schiller Jr.

Yeah. The actual drilling was fairly quick. But, yeah, the trip in and trip out, I mean, it’s taken us a couple of days to go back into the hole after we’ve been logging, because we’ve got to get in, we’ve got to displace mud, tunnel mud way back from 18,600 then 18,200, which is what we’re leaving the hole to log. So it’s a two to three day process to get back on bottom. And then we core. Then we come out of the hole in about 36 hours.

Eric Anderson - Hartford Financial

Wow. Where did you store all that pipe while you’re doing that?

John D. Schiller Jr.

It’s a big rig. That’s all I can say. Big rig, big derricks, lots of room for lot of pipe.

Eric Anderson - Hartford Financial

So you don’t have any barges? It’s all on the rig?

John D. Schiller Jr.

Oh, yeah. Everything’s stacked in the derricks.

Eric Anderson - Hartford Financial

Wow. If you get down to 29,000 and you got some nice looking pay sand, is there anything that says you can’t keep going with the permit you’ve got to 29?

John D. Schiller Jr.

Yeah. We’d have to extend the permit. But there’s no reason to expect we couldn’t. It’s just how far you want to push your luck. And it’s really not a conversation we had. It’s a conversation we’ll have once we see what this last 400 feet has.

Eric Anderson - Hartford Financial

And my last question is, are there any plans yet for where the Rowan Coffman rig is going first?

John D. Schiller Jr.

There are. We’re definitely going to put a rig on Blackbeard East as our next prospect. Whether it’s the Coffman or the Mississippi is still a little bit up in the air.

Eric Anderson - Hartford Financial

Are they still debugging the Coffman rig or is that ready to go?

John D. Schiller Jr.

I’m sorry, say that again?

Eric Anderson - Hartford Financial

Are they still debugging that? I mean, that’s a brand new rig or is that ready to drill whenever you guys give it the green light?

John D. Schiller Jr.

Actually McMoRan has picked up that rig and they’re drilling a couple wells, I believe at the Main Pass 299 area.

Eric Anderson - Hartford Financial

Breaking it in over there?

John D. Schiller Jr.

They’re breaking it in over there. I think there’s shallow long reach wells that they wanted to get drilled. So they’re kind of breaking it in. And then that rig will most likely move to Blackbeard East. And the currently thinking is mid April, guys? First of April is where it’s currently scheduled at.

Eric Anderson - Hartford Financial

And that’ll take you most of the year to get down to?

John D. Schiller Jr.

That will be six or seven months drill, yes.

Eric Anderson - Hartford Financial

Okay. Well, congratulations.

Operator

Now we’ll hear from Andrew Coleman with UBS.

Andrew Coleman - UBS

The question I had was, I guess, on the acquisition side, we got quite a bit of activity here on Davy Jones. How do you guys think the acquisition market’s looking and does all the success at Davy Jones kind of give you pause in any kind of medium term acquisition plan?

John D. Schiller Jr.

I think I tried to touch on that but I muddled through it. So let me clarify it up. We will continue to look. There’s a lot of deals coming out on the street. We’ll go look at them all. We are not – with where our current stock price is, all that enamored. We’re doing a deal that will require a significant amount of equity.

So there’s some bolt on deals that we can expand on the balance sheet and pay off pretty quickly with cash flow, then we’ll look at that type stuff. If it involved issuing equity, we’re not as interested in it right now because we just think there’s a lot more upside to come in our stock as people fully understand the size and breadth and width of Davy Jones.

Andrew Coleman - UBS

Okay. And then just to reiterate, I think what I heard earlier, then on production phasing from the remainder of fiscal 2010, it sounds like – and I have a – mostly just restarts coming on through the end of the current quarter and then we’ll see Cap Ex start to pick up probably starting in fiscal 2011 on the organic side?

John D. Schiller Jr.

Actually you’re probably going to see us spend close to $120 million, $125 million for this fiscal year. Some of that is the continued ultra deep drilling with Blackbeard East. And some of that will some recompletions in a drill well out at South Timbalier 21 to take advantage of rig prices and oil prices. So we will see some production later this fiscal year of that work.

Andrew Coleman - UBS

Great. Thank you.

Operator

And now we’ll open the floor up to Evan Templeton with Jefferies.

Evan Templeton – Jefferies & Co

Most of my questions have been asked. But I guess a follow up just to the last question regarding acquisitions. It’s safe to assume that whatever you look at it’s probably going to be oily with a decent PDP component?

John D. Schiller Jr.

That would be a good assumption.

Evan Templeton – Jefferies & Co

Okay. And then just, I guess, one other follow up. In terms of the – you’ve got two slugs of production, you mentioned one coming back in mid January, which was about 1,000 barrels a day and then you had the final, which was about 3,000 scheduled from mid February. Is there anything that could cause that timing to slip on that last 3,000 or for not the full volumes to material or is this purely just kind of mechanical, get the price connected and you are good to go?

John D. Schiller Jr.

Well, as most things this time of the year, Evan, we’ve already got the lines in the trenches. We’ve hooked up the 10 inch line, which is a gas line. Now we got divers in the water trying to hook up the oil lines. So you’re really dependant on big north cold front. So if the cold fronts come through, chop up the water, we don’t get a lot done. So right now, we’ve been pretty much heading on schedule for what we thought. We got the gas line in despite the weather. It wasn’t outside the amount of weather days we’d already built into our schedule. So if the weather holds like this, then, yeah, we’re in good shape.

Evan Templeton – Jefferies & Co

Fantastic. That’s it.

John D. Schiller Jr.

The stuff that would take you a long period of time is all done. We’re not waiting on a derrick barge or anything like that. We got the divers actually making the connections.

Evan Templeton – Jefferies & Co

That’s great. Thanks guys. Great quarter.

Operator

And now we’ll hear from Joan Lappin with Gramercy Capital.

Joan Lappin - Gramercy Capital

Good morning, everybody. One of my questions is, you reentered Davy Jones because it was already there. First of all, if you were to give us a one paragraph summary about why everyone is so excited about Davy, what would it be? And secondly, Davy, I guess wouldn’t have been if you were starting from nothing, wouldn’t have been the exact place you would have gone. So what is the impact of that as you pick where you’re going to do your straight down next job?

John D. Schiller Jr.

If I were to summarize it in a paragraph, Joan, I’d think I’d start with, it’s all about the pressure regression. And the fact that pressures have been decreasing as we drilled this well are indicators that you have to have big sand packages and sand packages that are continuous. That’s the only way you can get that pressure off of the reservoirs. So that’s the thing that has us most excited is, you feel really good when you look at that data and understand that you got a high probability that these sands are continuous across most of the structure.

Yes. We did reenter existing well bore. Out of a potential 20,000 plus acre structure, we’ve got about 7,000 acres up dipped to where we drilled. Actually, when it’s all and said and done, it’s not a bad location. I mean, it may be a little bit further off the flank than you might have chosen for your first well. But at the same time, as it’s worked, we’ve got a 1,700 foot vertical hydrocarbon column where we came into pays at just below 27,000 feet. And we’ve been in it ever since. Every sand we see has gas in it. So that’s proved up a huge area for us.

Joan Lappin - Gramercy Capital

Okay. Now, as far as the other Blackbeard East, all of that stuff, the group I gather was meeting over the last couple of weeks to decide what you’re doing next. Is there anything you can tell us about what was decided?

John D. Schiller Jr.

Yeah. I think what I was talking about previously, the next well we’re going to drill is going to be the Blackbeard East.

Joan Lappin - Gramercy Capital

Okay. And why that one?

John D. Schiller Jr.

It’s based on – it’s going to be a lower Miocene target for one, okay. It is not – let’s get that straight first. It is not a Wilcox target like Davy Jones. It’s a lower Miocene. It’s playing off what we say in the Blackbeard well. It’s coming back to the east where things are a little shallower than what we say at Blackbeard West. And we like everything we’ve seen on the seismic there.

The next prospect after that will most likely be Lafitte . And we’re working with MMS on that. What we don’t know for sure yet is the timing of when we get on the Lafitte well.

Joan Lappin - Gramercy Capital

Okay. And as far as the equipment and the – I don’t know what you call them, subsea blowout preventers or whatever, is there going to be any significant amount of wait time to get the equipment that you need to control the pressures that you’re going to be dealing with when you go to produce?

John D. Schiller Jr.

Yeah, Joan, there’s a couple of lead items you’re probably talking about. One’s your well head, and one is your surface controlled subsurface safety valve, which is an MMS requirement on every well we put in the water. We have to have the ability that if a boat comes through, knocks the well head off, we’ve got a value down there that’s failsafe and shuts in the production, so we don’t have an uncontrolled release of hydrocarbons.

Those are the two most critical items. And they’re totally dependent on what we determine our well head pressure to be. And that’s what I was talking about earlier in terms of using RFT to get us some pressure data. That’s going to be a very critical step for us. Because then we can quit playing a guessing game, which we’re playing a guessing game right now. And based on everything we know, there’s a decent chance that 20,000 pound equipment will handle it, especially if there’s a decent amount of condensate with the gas.

But once we get a real pressure and samples, then we’ll have a much better idea of exactly what we’re dealing with. And of course, finally I’ll be able to give you a time line as to when we expect that test/first production.

Joan Lappin - Gramercy Capital

Well, it seems to me you guys have been pretty busy the last few weeks. And you have a lot to show for it. And thank you.

John D. Schiller Jr.

Thank you.

Operator

And now we’ll open the floor up to Tom Romero with Capital Research Partners.

Tom Romero - Capital Research Partners

Hey, John. Thank you. Great quarter, congratulations. Just a tad of housekeeping on the logic. The five for one reserve split, basically, I think going from 146 million shares to 29 million shares or a little over 29 million shares, obviously, institutional ownership, would you just spend a moment just talking about the rationale there and the distribution and the free float?

John D. Schiller Jr.

Yeah. But let me get you straight on a couple things first. We went from about 250 to 50.8 million shares, 254 to 50.8 million shares outstanding after we did the equity offering.

Tom Romero - Capital Research Partners

Okay. I’m sorry. I was looking at data before that. Thanks.

John D. Schiller Jr.

That’s fine. So there’s a lot more float than you might think, A. B, it goes back to September, October, November, when we’re preparing our proxy, where our stock price was at the time, and we wanted to make sure we had the ability to do things, frankly to stay listed on NASDAQ and things like when we were selling for a dollar. So we put that out to a vote. That vote was going on while we went on the equity road show. And with our underwriters, we made the decision that for the funds like you referenced to be able to invest in the stock we needed to make a commitment to them that if we got the shareholder vote, we would do a reserve flip that resulted in something in the double digits. And the ratios we had to chose from were 2.5, 5 and 10-1. And one to five was the winner. I don’t think any of us wanted to see a $40 stock right off the bat.

And you got to remember, there’s old school, new school thoughts on reverse split. But one thing I’ll remind you is, unlike most IPO companies who came into the world at a $14 to $17 sort of price, we started life at a $6 price. So we never really were in that ideal range where you try and get your stock for initial trading.

Tom Romero - Capital Research Partners

Thank you. Great quarter.

Operator

And now we’ll hear from Biju Z. Perincheril with Jefferies & Company.

Biju Z. Perincheril - Jefferies & Company

A couple of quick questions. First John, given the size of the well bore on the current well, what sort of rates do you need to see on a production test?

Steve Nelson

25 to 30 (inaudible) more than that. 40 would be max.

John D. Schiller Jr.

So with the current tubing we're looking at running, Biju, we'll probably get a test in the 30 million to 40 million range. We could float at 50. There's two different animals. What do you want to float at the test and what do you feel comfortable on erosional velocity flowing out for an extended period of time. As it is right now, what we're approaching is, if we go with three and a half inch tubing, which may be the most we can get inside the tieback that we have on this well.

Biju Z. Perincheril - Jefferies and Co.

So if you see 30 or 40 with a three and half inch tubing with a normal size, do you think that will be closer to what rate?

John D. Schiller Jr.

We would design our new well bore – this is all still in the planning stage, mind you, but we'll be shooting for four and a half inch.

Biju Z. Perincheril - Jefferies and Co.

Okay.

John D. Schiller Jr.

Which is where you can start getting some chance for higher flow rates. A lot of that is just – let's get this first well under our belt, see what the liquids are and those type things. And that will give you a lot better guess on what kind of flow rates we're going to see.

Biju Z. Perincheril - Jefferies and Co.

Okay, that's fair. And then looking at your CapEx program, if you are running three rigs ultra-deep what would be the – it depends on promotes and so on, but what would be a ballparkish capital exposure there?

John D. Schiller Jr.

We said in our opening comments somewhere between $50 million and $75 million, $75 million kind of the outside.

Biju Z. Perincheril - Jefferies and Co.

For a three rig…

John D. Schiller Jr.

I am sorry, you said for three rigs?

Biju Z. Perincheril - Jefferies and Co.

Yes.

John D. Schiller Jr.

Yeah, three rigs, you start pushing close to $100 million.

Biju Z. Perincheril - Jefferies and Co.

Okay, very good. That's all I had. Thanks.

Operator

And now we'll go to Richard Tullis with Capital One Southcoast.

Richard Tullis - Capital One Southcoast

Good morning. Congratulations on all the progress you guys have put forth over the last couple of months. Most of my questions have been touched on already, John, just maybe one or two more. Looking at the slide in the presentation where you look at Davy Jones as a 1.5T discovery, what metrics were you using to get to that number, the pay, the hydro yield, all that?

John D. Schiller Jr.

You know you've got 7,000 acres up dip, so the number you get is a lot bigger than 1.5Ts. What we're trying to show you is that the first ten wells, we make 150Bs a well, here's what you get. That 1.5Ts is really geared towards -- that's what you get out of ten wells and not the size of the reservoir where we think it is currently.

Richard Tullis - Capital One Southcoast

I see, so you're looking for a recovery of about 150Bs from each of the ten wells?

John D. Schiller Jr.

Right. We're just trying to show you what the first ten wells would look like.

Richard Tullis - Capital One Southcoast

I understand. Looking at the additional ten to twelve ultra-deep prospects, are those all Wilcox or are you including Blackbeard East in that number?

John D. Schiller Jr.

Yeah, that is a combination of both lower Miocene and Wilcox and Tuscaloosa. So you have little bit for everything depending on where you are.

Richard Tullis - Capital One Southcoast

In general, as you are going into these wells, what are your pre-drill estimate ranges on these?

John D. Schiller Jr.

On terms of reserves? What number would you like it to be? The structures are so big that we, in our estimates, when we show you numbers, we kind of put 2 TCF sort of per prospect. And I think in our latest slide where we show you 34Bs gross – 34Ts gross, that's got Davy Jones kicked up in there.

Richard Tullis - Capital One Southcoast

Okay. You know a ten well program, you may have touched on this already, how quickly do you think that would happen. Ten wells would be producing by when in your estimation?

John D. Schiller Jr.

Here's a ballpark. You've got six, seven months to drill, and another month or about 45 days to complete. So let's just call it conservatively eight months per well. In our mind, and what we’ve modeled here, we would drill two more development wells, and the current intentions are to slide this rig and start the second development well – the first development well. Once we drill two more wells and you've got a kind of triangle around this structure, then in our estimation, we'd probably be willing to go to two rigs running. So sometime in 2011, late 2011, you pick up a second rig, and then basically you're drilling two wells every eight months.

Richard Tullis - Capital One Southcoast

Okay. And you expect just normal declines, Gulf of Mexico types declines on these wells?

John D. Schiller Jr.

Well, you know these wells are going to flow 75% of their reserves in a flat line. Whatever you bring it on, it's going to stay flat. That's how a normal high pressure South Louisiana offshore well works. Everybody gets caught up in these decline rates, but the reality is, when you bring on wells like this, if you bring it on a 100 million a day, and it's going to make 150Bs, you're going to make close to 120Bs without ever having a rate fall. You're just going to be opening up your choke as your tube pressure comes down.

Richard Tullis - Capital One Southcoast

What about the takeaway capacity out of that area? Do you see any issues with that?

John D. Schiller Jr.

No. Especially early on, it's not like we are going to wake up one day and all of the sudden have 500 million a day of production, right, so we can plan for it. But you’ve got a lot of shallow fill capacity right now, most of it as you might expect is Chevron's, and the McMoRan guys have been working really hard with them, so we’ve already got some plans in place, but takeaway capacity is not one of our big concerns.

Richard Tullis - Capital One Southcoast

Okay. All right John, thanks so much.

Operator

Moving on, we'll now hear from Ron Mills with Johnson Rice.

Ron Mills - Johnson Rice

I think all the operational stuff is done, but West, I had a couple follow ups on your costs. You talked about LOE and G&A and you had some incremental expenses in the second quarter. What's a good range to look for in terms of both LOE and G&A here in the third quarter and fourth quarter?

David West Griffin

The G&A I think I mentioned is that we are looking for something in the $10 million range for G&A in the March quarter, and that includes some allowance for the continued stock appreciation that we've realized in December. And then on LOE, I think on that we're going to see on the direct LOE more or less in line of where we are, maybe up just very slightly on that. But the insurance portion of LOE, as I've mentioned before is sort of going to be falling down to sort of the $2.75 per barrel sort of range in the March quarter if we get the full period effect associated with things, so your total LOE should decline.

Ron Mills - Johnson Rice

On an absolute basis, or a unit basis?

David West Griffin

No, on a unit basis it should decline. Total LOE will go up because we've got a lot more barrels with the Mit acquisition, but on a per unit basis it declines quarter over quarter.

Ron Mills - Johnson Rice

Okay. And then just it sounds like that, with the (inaudible) with one of the Rowan rigs going to Blackbeard East, John, what's the time frame you think before that begins? Do you have to wait for McMoRan to finish with whatever wells it's drilling with that rig right now? Is that something you can start here by the end of your fiscal year?

John D. Schiller Jr.

I'm sorry, I missed the very first part – are you asking about the Coffman rig?

Ron Mills - Johnson Rice

Or whichever rig you take to the Blackbeard East, I'm just curious in terms of timing.

John D. Schiller Jr.

We expect it to be early April right now based on everything we know. It's doing work for McMoRan at Main Pass 299 and our current schedule between the partners is that that rig moves to Blackbeard East early April.

Ron Mills - Johnson Rice

Another development well at Davy Jones is that the timing of that dependent on you getting both the fluid sample and a test rate, or would you move forward before you even have a test rate, given the lead time on some of that equipment?

John D. Schiller Jr.

No, that's – we're going to slide over and drill a second well at Davy Jones.

Ron Mills - Johnson Rice

Okay, everything else is set. Thank you, guys.

Operator

And now we'll go to Pritchard Capital Partners' Steve Berman.

Stephen Berman - Pritchard Capital Partners

Good morning, first a couple of housekeeping questions. The December quarter interest expense $24.3 million, was there any sort of non-recurring stuff? I'm just thinking to John’s comment about $85 million of annual interest expense, should we work out to a quarterly number lower than this. So is there kind of a call it a clean or going forward interest expense number to work into that?

David West Griffin

Yeah, in the December quarter, you have - interest expense gets distorted a fair bit because of the bond exchange. And so on an annual basis, I think that the key thing to think of is what is our cash nut that we have to spend on interest expenses. So the cash portion is 14% times $338 million, 10% on $277 million and then call it roughly 4% times the amount of our revolver outstanding. So that gets you your total cash nut on annual basis.

From an accounting standpoint, and what we'll report on a go-forward basis is substantially distorted due to some non-cash elements associated with it, and there's a really detailed footnote that will be included as part of the 10-Q to explain all of this.

But basically it deals with the fact that we did the bond exchange and while the 10% note holders who exchanged their bonds wrote off 20% of the base amount or principal amount of their debt, we did not recognize that upfront but rather amortized that over the remaining life of the second lien bonds and that shows up as a reduction in our interest expense. And then we have some other items that kind of go the other way, so it's a pretty complicated calculation.

Stephen Berman - Pritchard Capital Partners

And then when do you anticipate the Q being out?

David West Griffin

It will probably be out tomorrow afternoon.

Stephen Berman - Pritchard Capital Partners

And just on a kind of going-forward basis, using the 50.8 million or whatever, the basic share count is currently what – how many potentially dilutive shares are there in addition to that?

David West Griffin

Well, if you look at it from – of all the preferred and converted, all the preferred to common, and all of the preferred is deeply in the money at this stage. You know prior to the reverse split, we had roughly 300 million, so you divide by five, so it's roughly 60 million.

Stephen Berman - Pritchard Capital Partners

I'm sorry, 60 million – okay, I got it. So it's roughly 60 million diluted shares.

David West Griffin

Fully diluted. Just shy of 10 million additional.

Stephen Berman - Pritchard Capital Partners

Okay, got it. Thank you very much.

Operator

And we'll take a follow up question with Michael Bodino with Madison Williams.

Michael D. Bodino - Madison Williams & Co.

Just to follow up, John, on drilling plans going forward, what's the status on John Paul Jones, and can you give us some more details on that?

John D. Schiller Jr.

A little bit. I mean it's fairly early on. We've got some more work to do there, and that well I think is currently anticipated to be at least a year out.

Michael D. Bodino - Madison Williams & Co.

Okay, so that's a calendar year 2011 event?

John D. Schiller Jr.

Right.

Michael D. Bodino - Madison Williams & Co.

Very cool, that's what I needed to know. Thank you.

John D. Schiller Jr.

Thanks everyone. I think that wraps us up for the day. I appreciate all of your interest and look forward to seeing you at our Investor Conference Day which I think is going to be Thursday March 4th in New York City. Thanks.

Operator

Ladies and gentlemen, that does conclude our conference for today. Again thank you for your participation.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Energy XXI F2Q10 (Qtr End 12/31/09) Earnings Call Transcript
This Transcript
All Transcripts