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

Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

Q3 2011 Earnings Call

April 28, 2011 10:00 am ET

Executives

Stewart Lawrence - Vice President of Investor Relations and Communications

David Griffin - Chief Financial Officer

John Schiller - Chairman and Chief Executive Officer

Analysts

Phil Dodge - Stanford Financial Group

Ronald Mills - Johnson Rice & Company, L.L.C.

Eric Anderson - Analyst

Joseph Bachmann - Howard Weil Incorporated

Dan Chandra - Brevin Howard

Jeffrey Hayden - Rodman & Renshaw, LLC

Duane Grubert - Susquehanna Financial Group, LLLP

Richard Tullis - Capital One Southcoast, Inc.

Michael Bodino - Global Hunter Securities, LLC

Unknown Analyst -

Steven Karpel - Credit Suisse

Andrew Coleman - Madison Williams and Company LLC

Nicholas Pope - Dahlman Rose & Company, LLC

Operator

Good day, ladies and gentlemen, and welcome to the Energy XXI Third Quarter 2011 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the call over to your host, Stewart Lawrence, Vice President, Investor Relations. You may begin.

Stewart Lawrence

Thanks, Stephanie. Welcome to the call today everybody. Presenting today is John Schiller, Chairman and CEO; and West Griffin, our Chief Financial Officer. We will be available along with the other members of the management team and answer your questions at the end of the call.

Before we get started, I need to remind everybody 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 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, and give a big, warm happy birthday to John before I do it.

John Schiller

Thanks, Stewart. Good morning, everyone. Our third quarter demonstrated the benefit of the Exxon Mobil acquisition and our oil focus as we posted record quarter results. Our production volumes rose 63% and EBITDA jumped 78%. We averaged $88.27 a barrel for our oil and $5.51 in Mcf for our gas post-hedge or about $69.46 barrel of oil equivalent. We expect these numbers to improve even further in the future. Volumes have been affected by a number of issues this quarter, mostly out of our control.

We have weather-related issues, pipeline and processing plant outages and our usual interruptions from compressors and other maintenance items. Importantly, though, there's no fundamental operational issue affecting our production, none of our large wells lost volumes or went off line.

In terms of cash flow impact, it didn't hurt that 2/3 of our shut-in production was gas, so we're still able to deliver strong cash flow numbers. We expect to grow volumes once again, once we gain day-to-day operational control of our acquired Exxon properties. Everything we've learned about the progress to date has made us more encouraged about the growth opportunities.

Examples of these include the Alabaster Field, Mississippi Canyon 397 that we returned to production, with a gross cash rate of over 870 barrels of oil a day, 500 Mcf a day or about 960 barrels of oil equivalent net for the company, that successfully reestablished production on a field that have been shut in for 60 days and gives us opportunity to continue to work with some other things we've identified there and push out the P&A [price and availability].

At our Grand Isle 16 field, we've done a sidetrack, an M-13 sidetrack well was recompleted to the Q-40 sand, that well's test is at 589 barrels of oil and 380 Mcf a day, or about 570 net to the company. We've also done another recompletion out there that's now flowing at a bit over 4 million a day net to the company.

Recompletion work is underway at South Pass 89, doing our coiled tubing work there. The rig will be showing up next week. We have at least 5 wells at work on there, and we're talking about 2,500 barrels a day net uplift. So far, none of the work on Exxon properties includes a drill well. This would change after the start of our fiscal year in July. Right now, we continue the rack and stack the opportunities to decide what were going to the fiscal 2012 budget. While I'm on the subject of Exxon, we continue to work day in and day out to give the operators shift for the remaining three fields that we have not taken control of yet. We're pushing that at the highest levels within the BOE. There seems to be some other companies in the same situation, including Apache and Dynamic.

We think we know what the issue is, which has nothing to do with us in particular and some things do with our computer systems, but we're going to keep pushing through for that. What I will say the good news is Exxon has agreed to work with us, so that we are actually now going to start doing some work on those fields that we want to get done even though we have not taken our operatorship of the assets.

Elsewhere in the portfolio, we have rotation wells to talk about. You saw the Pontiff well that McMoran announced with a 5j4 minute a flow rate. I'm happy to tell you that as of 1:00 this morning, that well is on production, with about 15 men a day, and we will continue to ramp it up. We also, as we've previously mentioned, expect to see a decent amount to compensate there along the lines of what we saw in the Peterson well, priced somewhere between 10 and 15 barrels in million. And based on the early stuff this morning, that is what we see in.

On the Ashton well, our results there have been nice. We've logged five face sent[ph] above the salts. We got into the salts a couple of hundred feet early than what we thought we would. We're still in the salt, and we're setting a pipe there, and we're going to move over and drill our Onyx well now and then we'll come back and get into the Ashton, going deeper looking for the J-6 and other sands.

Our shallow water, ultra-deep program continues within wide anticipation. Davy Jones, we have ongoing logging operations. We have made two runs. We have not gotten a full suite of logs yet on our redistributing tools have failed twice going in the hole. We have seen a gamma ray, sands, et cetera all the way to TB. Right now, we're going to go in there with some gauges to get us some pressure readings and that's what we're rigging up to do right now. That will be done on drill pipe.

Over at Blackbeard East, we have now recovered 1,870 feet of the original 3,239 feet of fish. That leaves us about 1,370 feet in the hole. We continue to make good headway there. We'll be going back in there to wash over some more and see if we can continue to get those pipe out of the hole.

At Lafitte, we're drilling at 21,258. We'd had to run a little expandable for somewhere up another 16-inch case, and that job is finished, and we're back to drilling. Casing point is called for 22 6, obviously we're looking for where we go through the salt, and that maybe subject to a little bit of change. I will turn it over to West right now for financials, and we'll get back in a little bit.

David Griffin

Thanks, John. Let's start with a look at the items affecting the quarter's financial results. The first time of note is the loss from a debt retirement, which we highlighted in the earnings release. It's shown as a separate line item in other income expense, amounting to approximately $12.2 million pretax. Two other sizable items for the quarter are not as the evident, but you can see their impact on G&A. The first is a $4.8 million stock-based compensation expense, related to the change in stock price over the quarter. We accrued this expense based on the end of the quarter stock price. So as the stock price rises, not only do we have the normal time-based accrual, but we also have to play catch-up on the previously accrued amounts due to the increase in stock price.

The other items hitting G&A were expense related to the Exxon acquisition, which totaled $2.4 million for the quarter. Some of these costs will carry into the current quarter since we're continuing to pay Exxon a fee to operate the three largest fields even though we've hired our own teams to take over once the government approves our operatorship.

Those items totaled $19.4 million, pretax, or $17.4 after-tax. So earnings per share would have been $0.42 or $0.23, a share higher than the $0.19 per share reported.

Looking at the operating data on a BOE basis, you can see that jump in volume from the Exxon acquisition. Production remained oil related, as reflected in revenues, which jumped to more than $71 per BOE. Look at it another way, that's 66% of production contributed to almost 90% of our pre-hedge revenues during the quarter. Getting a little more granular, we reported oil volumes for the quarter of 27,300 barrels a day. About 7% of that was actually natural gas liquids, which helps explain why the revenues for barrel might not look exactly as you expected.

On a pre-hedged basis, we actually received $97.86 a barrel for oil and $55.25 a barrel for the NGLs, taking the reported pre-hedged revenue to $94.94. Keep in mind, those are averages for the quarter. March oil brought in $111 a barrel on a pre-hedged basis and our realized prices continued to go up since then.

On the expense side, direct LOE rose due to the higher cost of the acquired properties. As I mentioned earlier, we already hired our own teams to operate the properties, of which part, but not all are currently working in the field. So on the three largest fields, we have some additional personnel who are shadowing excellence. We're essentially paying some costs twice until the BOEM transfers operatorship.

G&A was higher because of the acquisition costs and stock-based compensation expense I discussed earlier. Without those costs, G&A for BOE would have been about $4 a barrel. The bottom line is that we delivered EBITDA at nearly $42 per BOE. Whereas we'd like to say, in contrast to the gas producers, that's about $7 per Mcfe of EBITDA, not revenue.

It's good to be oiling.

Those EBITDA levels led to an $80 million reduction in debt during the quarter. Going back a little further to December 17 closing of the Exxon acquisition, we reduced debt by about $93 million on a net-debt basis. This slide shows the balance sheet improvements we've achieved in the past couple of years. All of our 16% notes and most of the 10% notes have been replaced with much lower cost debt, which also extended the terms out several years. The remainder of the terms are currently being called and will be retired by June 15.

That $106 million of 10% notes will be retired using a revolver, which is low-cost debt that we'll continue pay down with free cash flow.

We have also received approval from our bank group to increase the revolver capacity by $50 million while lowering the cost by 50 basis points across the board. Net debt to gross capitalization is down significantly and heading lower. Net debt to market capitalization shows an even more dramatic reduction. All in all, we have made tremendous drives in fixing the balance sheet and this cash flow machine we felt should continue to improve our financial discretion.

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

John Schiller

Thanks, West. The fiscal third quarter was the best quarters in the company's history with record production cash flow, acquired properties are even better than we have imagined and our teams are tromping us a bit to get to work on them. Many of you will have the chance to meet those teams and see their enthusiasm for yourself at our May 13 Investor Day in New York. On the drilling said, the Pontiff well, it appears, have significantly expanded the size of the Laphroaig discovery and will contribute in excess of 1,000 barrels of oil a day net volumes to Energy XXI, pretty much maintain that at a flat rate over the next year or two. The Ashton well expanded our Main Pass 73 field and sets us for further reserve and volume additions. And then the ultradeep play keeps gaining steam with every piece of data.

We look forward to continue the string of success in the near future. With that, operator, let's open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Dan Chandra from DW Investment Management.

Dan Chandra - Brevin Howard

Can you walk through the increasing in your CapEx guidance for this fiscal year, I guess, where that's allocated to? And I assume for the amounts for the Exxon acquisition for the Exxon properties, you had a pretty good payback on that?

John Schiller

Yes, exactly, Dan. We're up over the whole year about $130 million. I'll break that down for you real quick. About $82 million is not leading directly to any production right now. That's $38 million to the P&A category. $12 million associated with G&A, so that's $50 million, plus $32 million on the ultradeep drilling for the year. Then the rest of it breaks out about $23 million in the recompletion department, which has obviously given its volumes, $29 million on new drill wells like all the excess work that we're doing at Eugene Island 330 with Apache, the Pontiff well which wasn't in our original budget and then a well we have yet to drill at Main Pass 60 that we're going to spud here before the year is out.

You put all that together and between what we're getting out of Pontiff, our 330 work, what we expect from Ashton and the South Pass 89 work with Exxon, that's probably somewhere north of 5,500 barrels a day of production we're bringing online. And then the Main Pass 60 well is a big well. We'll talk a little bit more about it at the Investor Day, but let's say it has huge volume impact. It's a tight well that should give us somewhere between 30 million to 50 million a day and it's a 100% well for the company. And that will be on our fiscal year '12.

Dan Chandra - Brevin Howard

30 million to 50 million of gas?

John Schiller

I'm sorry, what?

Dan Chandra - Brevin Howard

30 million to 50 million a day of gas?

John Schiller

Yes.

Operator

And our next question comes from Duane Grubert from Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP

Yes, John, it's your birthday, but it's also the past the birthday for both the Davy Jones and the Blackbeard East well. Can you talk to us a little bit about the incremental costs on the AFEs for those wells and how much in your capital budget increase have you had relative to the slowness of the projects versus the incremental work?

John Schiller

I will tell you this. Let's start with Davy Jones. We're going to be in the neighborhood of 160 gross there. When you look at versus AFE, we were about 15% of 20% above AFE, which should have put us around 120 to get to -- through the Wilcox sands where we originally td this thing or plan the td before we went in to Tuscaloosa. So a lot of it has been coming on as we've been trying to drill through the Tuscaloosa and the slowness of that drilling. At Blackbeard East, similar things. We actually were through and to our targeted AFE of 29,950 barrel for about 15% over AFE. And so everybody gets -- they look at the total numbers, but you got to remember we're drilling these things a little bit deeper than where we were expecting to be. At Blackbeard East, now that number is -- we're expecting all in to be done at about $193 million right now or $170 million in there. So we'll just keep working on those wells. We know there's a lot of room for improvement in there, but I'll talk to a bunch of you about our flat times are what kills us. Typically, especially early in the holes when we're drilling, our drill rates are better than anything we have predicted. What we got to work on is our nonproductive drill time, when we're not making any holes.

Duane Grubert - Susquehanna Financial Group, LLLP

In the general increase in activity, particularly with the Exxon stuff, can you talk about how much manpower increase you need if any?

John Schiller

In the office standpoint, we're bringing in about 25 people total. Of that 18, 19 professionals. What we're doing there is we're adding 3 teams: geological engineering teams, probably half of 60% of the teams on Exxon are being staffed by our existing personnel and they were backfilling behind them and the legacy asset teams. And then some of the people we're bring in are specifically targeted for knowledge and opportunities around the Exxon stuff. In the field level, a significant increase there, we added 30 positions for the company and supervisory and maintenance and things like that. And then from a contract standpoint, we're down significantly from where Exxon was once we get over control of everything. But we put on in excess -- we're going to put on about 100 contract people through Wood Group in Ireland.

Duane Grubert - Susquehanna Financial Group, LLLP

And then, finally, on the low hanging fruit where you have this really terrific results from the small recompletions, et cetera. Can you talk a little bit about the visibility of how much really cheap low hanging fruit projects you see right now versus getting into a little bit higher risk and higher cost type bread and butter projects?

John Schiller

Yes, Duane, it's a very fluid situation that's ongoing as we see one idea work, we're looking for multiple other ideas. For instance, what we did in Alabaster, there's one or two more identical situations like that. One of which, when we're going to do a [indiscernible]. So like this weekend, we're going to do another one and that's a job where we think there's a similar situation. We're identifying a lot of the behind pipe stuff that we think that's a good opportunity going. Those cash for recompletion existed. So 4 million a day out of that. Before we got on it, we might have told you we would have been happy with 2 million. And at the moment, gravel-pack completion, it's not gravel pack, so we're probably not going to go a lot higher than $4 million. But a lot of those things are just one-to-one deal works that triggers the guys to go look for more opportunities like that. My gut is -- I won't say there's 50 more opportunities like this, but I'll be stunned if there is not a dozen more like this. We just got to keep going through everything and doing the work we're doing and identifying it.

Operator

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

Richard Tullis - Capital One Southcoast, Inc.

John, going back over to the CapEx real quick. So that difference between now versus the guidance in February, like $40 million difference. Is that almost all related to the ultradeep?

John Schiller

The $130 million total difference from when we started the year, a bunch of it, Richard, is P&A where we've just, to be honest with you, there were some softness in the market. We were able to do a lot more P&A work for a lot less. And so we went ahead and jump some things forward this year to clean up. No government or anything else involved in it. Just us doing housecleaning, and we had a situation with a couple of vendors were getting a lot more bang for the buck. So we accelerated that work. $32 million of it's ultradeep. $12 million of it is G&A, which is what we already talked about as almost all about stock-based compensation. And then -- so that's like $82 million out of the $130 million and the rest is what's given us the volumes.

Richard Tullis - Capital One Southcoast, Inc.

The $190 million cost expectation for Blackbeard East. Does that assume that you retrieve the remaining pipe in the hole, continuing at the existing whole down to the deeper zone? I mean it's not factored in as a potential sidetrack.

John Schiller

Sidetrack will be a lot less, and I think it's been pulling out there. If we side track and we uphole like we're talking about the 25,000-foot sands. That's 35 million, somewhere in that neighborhood.

And part of the whole, if you remember where we're making 400 feet a day.

Richard Tullis - Capital One Southcoast, Inc.

Production, what are you currently producing? What is your average for April?

John Schiller

We did a lot around 41,000 for April so far. I'm talking in line with this quarter and I'll be 100% honest with you that's driving declines at Exxon until we get control of the field. I mean, you sit back and think about what's going on. You got a group of guys that are just like me and you and everybody else who's ever changed a job, on March 1, they'd all expect to have a new job. Some of them are going to go work for us. Some for Wood Group, some stay with Exxon and a new job and some will leave and then retire. And we're two months into that not happening. And frankly, there's some I-don't-care attitude going on. So while it gets shut in, they stay shut in a little bit longer than they were in the past. To Exxon's credit, the fact they're going to let us go out there and start doing some work is going to help on that. But that's we'll find day in and day out, and it's our government at its best. As I've told you guys in the past, we're getting our permits, but these administrative well issues like this, if they're hung up over what we think they're hung up over, it's such a silly issue. It's not even funny in terms of what is impacting us versus what the issue is, which has to do with just drilling wells from one lease to another and how their systems handle it.

Richard Tullis - Capital One Southcoast, Inc.

Once you get the full operatorship, what do you think you could do second half of the calendar year?

John Schiller

We feel pretty good that we're going to ramp up volumes pretty quickly here. I mean, the things that we'll find are easier to fix. If you see the kind of things we're doing, wells like the Pontiff when they start playing out 1,200 barrels a day, day in and day out, without any reduction in volumes are going to flow 99% of the time. Same thing with the Ashton well. We start laying those wells in. You're going to be up 10%, 15% pretty quickly from where we're at.

Richard Tullis - Capital One Southcoast, Inc.

And then last one for me, I'll jump back in the queue. What's the outlook for booking proved reserves on any of the ultradeep at your year-end, calendar midyear?

John Schiller

Well, what we're doing right now is Davy Jones is going to get pressures. It's going to be a big part of that. We got to get pressure data, we got be able to show some of the common billing data. Whether that will be enough, we'll just see comes June 30. I mean, we're going to have to go pretty good evidence on the drilled EBIT flow I think to get the book proved right now. And I should just see what we got. I will tell you that with the other drilling we're having, the success we're having, as in Eugene Island, Pontiff, all those things, we're going to have a good reserve here without anything from the ultradeep.

Operator

Our next question comes from Jeb Bachmann from Howard Weill.

Joseph Bachmann - Howard Weil Incorporated

A couple of questions on the 2 deep shelf prospects. One with Ashton, how's that network exceeded expectations at this point and also just want to about Onyx a little bit, if you can.

John Schiller

Sure. At Ashton, we saw the first five pay sand that was a thicking damp up dip, which is not a typical Gulf Coast model. It is what we expected, so we're happy with it. It's just typically going in the salt, you see thinning rather than thickening. So that was a nice confirmation, what we saw. We hit the salt a little earlier than we thought, which cost us one sand at the bottom. And we're in it a little longer than we had modeled. So we're going into pressure and then when we finally got it to be pumped into the J-6 sand, we're okay. If we come out and we're below J-6 sand, we pop out in the pressure. So we're going to sit tight wherever we are and slide over and drill the Onyx well. Onyx stays above the salt the whole time, so we feel very good about that. The short, sweet summary meeting, the interpretation down to salt looks to be 90% accurate below the salt. Our thickness may not be 100% right that's what we're going rework real quick on Ashton, but in the meantime, that has no impact on Onyx.

Joseph Bachmann - Howard Weil Incorporated

And then what kind of resource potential are you looking at Onyx at this point?

John Schiller

I think Onyx is 1 million to 2 million below equivalent somewhere in there. And the big potential there is obviously below the salt with Ashton. We get in some of the field pay sand there deeper and we can put a lot in there with that track.

Joseph Bachmann - Howard Weil Incorporated

But that 2 to 3 in Ashton still even with the thickening better than expected still kind of a good estimate right now in the initial targets?

John Schiller

Yes, that was one big tick. We're probably $1 million to $2 million with what we have going deep. It should be another $2 million to $3 million below the salt.

David Griffin

You have to see what we see when we get back in there.

Operator

Our next question comes from Ron Mills from Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

Question just to follow up, I think, on Richard's question on the production, you're about at 41,000 barrel a day level during April. How do you think the rest of your fiscal fourth quarter shakes out? I'm just trying to get a sense in terms of how much of the production was impacted by weather and pipeline and processing and compressors and in your fiscal third quarter. I'm just trying to look ahead to this current quarter?

John Schiller

I mean, I think from where we are right now, we've started bringing on volumes. Obviously, the pontiff well is coming on. It wouldn't surprise me if what we average this quarter is another 41. I just don't know when I'm going to get hold of Exxon. I'd say we feel really good of the quarter. Every bit is as good as the quarter we just had, and we think we got some upside from there. Let's see how the South Pass 89 recompletion program comes together. You bring it on Pontiff like we talked about. We got about 2,000 plus barrels a day that's still down for various reasons. And so as we bring all that on and we could go to the upside from there, but let's call it 41 again for those quarter and then see what happens with regardsto Exxon assets.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then on the CapEx, you walked through what the differences are, given what you've spent through the first 9 months of the year, is that 380 which you think you will spend or what's you're authorized to spend? Because that would imply a really steep ramp here in the last three months of your fiscal year?

John Schiller

Yes. It's what we're authorized to spend, and it's a good point, Ron. If I had to tell you right now if I would tell you it will be 15 million to 20 million below that when it's all said and done. But we have a board meeting this weekend. We kind of showed them the them the max case for everything. You're going to have pretty much all of your wells get approved with minimum delay anywhere to even come close to that number. So my gut is that we should be below that number.

Ronald Mills - Johnson Rice & Company, L.L.C.

Just directionally, next year that would put you on a run rate that would be anywhere from likely 25% to 50% above this year's number?

John Schiller

No. I mean, you going to see next year, the next couple of years budget plus or minus $25 million, around $400 million. So what we end up doing this year is count the burn rate for the remaining years.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then what would be in that scenario, given your strong cash flow and EBITDA generation? You've obviously start kicking off a lot of excess cash you have after you get these 10% notes brought back in, your debts in really good position. What is on your wish list in terms of some of that incremental cash in fiscal '12 and beyond?

David Griffin

.

Our objective right now is, as we've indicated before, is to get our debt down a bit more. We want to get it down below 50%. That's the total capitalization. We're a little bit above that right now. Anticipate that we'd probably achieve that some time in the next 12 months. So that's kind of the short-term or short intermediate objective here.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then just on the outlook for G&A and LOE and also you didn't really discuss BD&A. What do you think the fourth quarter for those? I think you talked about G&A, we can back off plus or minus $7 million for one-time items although some of the Exxon costs will remain in this quarter. And then how quickly do you think you can ramp down on the LOE or is all that dependent on assuming operatorship at Exxon?

John Schiller

Well, obviously, taking over operatorship is a big piece of that. [indiscernible] that's $1 million difference, which I will remind you, Ron, is round off. When you remember the big buzz is Exxon asset in an $80 world. We've had protected it. One of the moves we've made in the last few days is we put some puts some puts in place at $100 a barrel or 4,000 barrels a day, 3,500.

David Griffin

3,500 barrels a day. So we've continued and kept our bunch of upside on Exxon. And when you look at that, to be honest with you, the cost differences in the volume fall outs we did round off versus what we're getting on the overall value in this acquisition. Again, LOE, as soon as we get volumes up, LOE is going to fall. We need to get a control. What I would say is 1 letter of action dynamic about letters, and we're going to elevate it even higher because it's long enough. We're talking about something that's typically a weak process to assign operatorship, and we're dragging on 3 plus months.

Ronald Mills - Johnson Rice & Company, L.L.C.

And then lastly, just in terms of pricing, it's been beaten to death how strong LOS relative to WTI. But you had a minor impact, a positive impact from that in your fiscal third quarter. How should we look at it from a pricing standpoint, your oil production year over the remainder of this calendar year given plus dollar differential, are you going to capture all of that delta or is there something in your hedges, caps?

John Schiller

West say that they actually answered, but I will tell you that we are also doing fiscal hedges from time to time. So we've had offers with [indiscernible] for the later half of this year at $11.25 a barrel. Sweeped up plus WTI. Some we left float. Overall, West, you can talk.

David Griffin

So on blowing portion, as you know, determined the differential prior to actually incurring the months. So today, as an example were the April and May differentials have all been set, and we're just now determining the June differential incurred. April, that differential is about $13 a barrel, $14.5 for May, on a floating amounts and then with our other hedges, if you factor those in, the differential for April would be about $6.40 and $7.50 for May. So call it on average about $7 positive differential to WTI.

John Schiller

And that's versus the historical $0.70 for our five-plus years of being in business.

Operator

Our next question comes from Andrew Coleman from Madison Williams.

Andrew Coleman - Madison Williams and Company LLC

John, a question for you. Is your age less than the Pontiff IP?

John Schiller

Yes.

Andrew Coleman - Madison Williams and Company LLC

Thinking about the Ashton wells a little bit further, of the 7 zones, can you comment as to what the thickness was of the biggest zone you guys encountered there and how that compares to I guess some of the pay sands in Pontiff or thickness?

John Schiller

Yes, we had 57 net data tie-in the first sand, that's an old zone and 35 feet below that. So that sand's thick enough to be a total of 100 per gross interval. That's probably a 25% increase over what was down there. Next sand had 24 feet a pay, if memory serves me, that's about 6, 7 feet thicker than was down dip. Next one is 39 feet and then the[indiscernible] which is a big one, 85 feet. All of those and then we have another 29 feet, another 12 feet. We actually got a fair amount of zones going on there. All of those in general, Andrew, thickened probably 10%.

Andrew Coleman - Madison Williams and Company LLC

On the Pontiff side, would you say that those are comparable numbers and should we look at -- it's a lower risk well than ones you see in the Pontiff, but those will give you some pretty good IPs as you'd bring them on, I'd imagine.

John Schiller

Yes. I mean, we're expecting 1,000 barrels a day from the oil zone. If we get gas and start there, which zone are you going to [indiscernible] doesn't even know yet. We haven't really decided, Andrew, what zone we're taking yet, but we're going through with Onyx and then come back and complete them. But that's why I try not to get you guys too hung up on volumes and why I said what I said earlier. We hit our cash flow number because of volumes and we were missing were predominantly gas, which has had a lot minimum impact. The flip side out of that equation is we bring on big gas wells. If you own a 100% of the Pontiff well, you're looking at making 9,000 barrels a day net for the company of that well. And it's going to be locked there for a while. I've been making here the revenue, but the bottom line is there's not many opportunities to have 9,000 barrels a day oil wells. Same thing at Ashton. One of these gas zones will probably easily do $20 million a day, maybe $25 million. So there's 3,000 or 4,000 barrels net for the company from a volume standpoint, but I promise you, I'd rather have 1,000 barrel a day oil completion that stays flat for a while. So that's just the difference in how volumes come into play for what we did.

Andrew Coleman - Madison Williams and Company LLC

And do you know if these are water drive or pressure depletion drive? Or is it too early to tell at this point?

John Schiller

Most of these, they're predominantly water drive, somewhat more depletion. It's not too early to tell because these are all -- all of these sands are 1,000 down deep and had been on production. So we know which zone, what our production mechanism is going to be.

Andrew Coleman - Madison Williams and Company LLC

Okay. And then looking at some more of the base operations there as you transfer the ownership from Exxon guys. You talked about a lot of recompletion work. Is there a lot of debottlenecking projects that you guys have, are those options or is it...

John Schiller

You're a dead on, Andrew. There's a lot of their fields with added well with pressures running about 300 pounds. And we think we can get that down at 100 pound range. And as you've heard me talk about before, when you talk about a good Gulf of Mexico average, you expect to make 4 or 5 barrels a day for every pound of pressure drop. So when you start taking wells from 300 to 100, you start bringing on anywhere from 700 to 1,000 barrels more fluid on the good wells. And so even with a 20% oil cut, those revolvers start making a difference and that's why Marchive's and Nelson's guys have done really well. It's what we always bet on. That's the stuff we're expecting again. All these other things we have been talking about the low hanging fruit, to be honest was never anything we were expecting to see. The other stuff is what we've always considered ourselves really good at when we roll up our elbows, our sleeves and get our elbows and hands dirty doing the work.

Andrew Coleman - Madison Williams and Company LLC

More of just straight LOE sort of spend, so you get some high margin oil coming on with those debottlenecking projects.

Operator

Our next question comes from Nick Pope from Dahlman Rose.

Nicholas Pope - Dahlman Rose & Company, LLC

Quick question on Davy Jones. As you look at the -- in the thing on the production, I know you pointed to the BOP being the kind of key kind of timing item at this point. As you kind of look at it is all of the other piece of equipment are kind of on schedule and with that piece, are you still expecting fourth quarter and late year production from that?

John Schiller

Yes. Thank you for bringing that up. Actually, I will tell you that all of the equipments, all the components have now been pressure tested. They all passed. So we're actually constructing now. The companies are constructing the true production, trees and valves and et cetera. Everything is on pace and I think you'll hear us start telling you during the summer about the delivery of most of these items. Well in advance and when we need them. The cost of the BOP as you alluded to, that's a long lead item time. But everything else is looking really good right now on schedule, no hiccups and no reason not to expect to have a well test in December. The way we'll do that is very similar to what we just did on the Pontiff well. Back then I'll pull up a catch barge operator. We'll flow the well initially through portable test facilities and run-on facilities. And get the well cleaned up and all and then if the timing goes as good as we think it is right now, we're in probably a max of 6 or 8 weeks and maybe sooner, we'll have commercial production right behind the well test.

Nicholas Pope - Dahlman Rose & Company, LLC

And the production when you bring it online, are you, do have things lined up on the surface with platforms and pipelines to get that out once -- after the test has been successful?

John Schiller

Yes. I just want to say the facilities right now should be scheduled and finished and in place. We're actually putting, I'll show you a lot of the detail at the Investor Conference, but actually, the Davy Jones #1 well will be location of Central facilities also. So we're setting a series of four pipeholes [ph] right there to host everything and give us room to expand.

Nicholas Pope - Dahlman Rose & Company, LLC

Are you expecting any significant like processing requirement at this point for the gas?

John Schiller

We geared everything in the hole to be able to handle H2S [hydrogen sulfied]. We have no reason to expect H2S. We're building a facility for CO2 and for H2S. We don't have anything on the facility for H2S. We don't have any reason to believe we're going to have H2S with everything we've learned drilling the wells today.

Operator

Our next question comes from Philip Dodge from Philly Brothers Investments.

Phil Dodge - Stanford Financial Group

John, here you say that you're running into a little different [indiscernible] that you thought particularly in terms of the depth of the salt and if that's so, could you elaborate?

John Schiller

No, Phil. I think I was talking about Ashton that the salt was a little thicker than we anticipated. At Lafitte, we're still, we got mixed interpretations as we usually do at this time in these wells. Some people think we're in the salt well. Some people think we haven't got there yet. We're close by anyway you look at it. What we haven't seen and what we typically look for in our shop is an agey [ph] jump in the rock. As you cross that the salt well you typically jump several million years, and we haven't seen that yet. But we're right there any day. So I said we're at 21 2, the casing point cost were 22 6. That's flexible, depends when we get into the salt weld and how thick this salt level zone is. You give back to Davy Jones #2 for instance as we drilled through the 10-foot salt well there, we had 1,400, 1,600 feet of old, old rock that it dragged up with that salt weld. And then we actually went down in age from that rock back into where we should have been in the sequence. So the level zones can always be interesting. You got to see what they are, and how thick they are and that will determine what you set pipe.

Phil Dodge - Stanford Financial Group

And as you going in, in terms of, is that correct?

John Schiller

Exactly. You look at seismic, where we are and where we thought we'd be. Everything is right where it's supposed to be.

Operator

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

Jeffrey Hayden - Rodman & Renshaw, LLC

Just a few follow-ups where we talked a lot about kind well across Blackbeard East and Davy. AFE kind of looking like right now at Lafitte, and has that changed anything.

John Schiller

I mean, Lafitte is, got a long way to go. The AFE there is predrilled with $112 million. We may need to go up a little bit there. It just depends. I mean given an example, Blackbeard East when we were at this point in time, we thought we're going to have to increase AFE a lot and then boom we started making 400-foot a day and we ended that within 10% of AFE when we got down to 29,000 feet. So it just depend. We're watching it everyday. We've been a little slow here. In casing repairs job, obviously one something we want to do, but let's see what happens as we go below the salt weld because that tend to be where we pick up the drilling.

Jeffrey Hayden - Rodman & Renshaw, LLC

And then jumping back to Davy, has your experience on this well kind of changed your expectation for development mode well costs?

John Schiller

Not really. I mean, we know what our issues were. We think we know how to drill better than that. We really want to see what we have in the bottom of these log here, which seen enough stuff that we're encouraged. We think we've seen the lower Tuscaloosa sands. We need something to tell us what's in the sand and that more than anything changes the whole dynamics for Davy Jones, we have 200-foot of Tuscaloosa sand falling to Ashton then we got a big hit there.

Operator

Our next question comes from Steven Karpel from Credit Suisse.

Steven Karpel - Credit Suisse

I just wanted to understand a bit more, John, on the [indiscernible] logs and the issues you're having. Is it temperature-driven? Is it is pressure? Are you changing the type of tool you're using now? What's going to work here you and what is an indication of the rest of the logging? Any problems you'll have there?

John Schiller

It's most likely temperature. We ran the first one on drill pipe. And these tools are rated to 500 degrees. But they are rated 500 degrees on wireline, okay? Which is a different animal when they're running on drill pipe. We ran on drill pipe to be 100% pipe is slick as log when we've made the date and then we went straight to bottom. We had no, but that's done a good getting the hole in good shape, but we lost the [indiscernible] tool fairly early on, which I think is just my comment to Jim Bob the other day is I think it's QC. When you look at the wells we've logged, you see a similar thing. You'll pick up the same tools to different times and one time you won't get anything. The next time you'd get every tool to td. So I think it's just QC around the combination of the pressure and temperature. So then we came out and we picked up a wireline tool and again within a couple of thousand feet to where we wanted to be to see the lower Tuscaloosa, we lost all saw the [indiscernible] tools. I'm not there. I haven't seen the tool broken down. I don't know if it was, I assume it's temperature-pressure combination, but the tools should be able to handle it. So I think it's just QC, there's only so many of these tools built. Now we're actually changing vendors, without remembering who is who there. We're changing vendor's and we'll run in a mechanical on drill pipe tool that's set to get pressures. And we expect that tool to work based on history that sells out around the world.

Steven Karpel - Credit Suisse

Are you seeing those same tools are used on Blackbeard as well and on DK1 [ph] ?

John Schiller

Yes and no. To be honest, we've kind of been all around on those wells from Weatherford to Baker to Slumber J around 2 to 3 times each of them. So all those tools have been running in various wells at different times. And all of them have had success at various wells at different times.

Steven Karpel - Credit Suisse

And then walk us through the sequence assuming that this one works what are the next call 2, 3 weeks look like in terms of steps you have to take?

John Schiller

I'd love to give that answer but I don't know if I'd better right now. Let's see where we get the pressures and what they tell us. We got to have that data. It's very fluid. Once we see that, it's going to dictate what our steps are. And then there can be anywhere from running another set of logs, making clean-out run, run another set of logs, run a pipe, drilling ahead. There's a lot of options. We just need to see the data we're getting right now. Right now, we have some sands and we want to see what's in them and we don't know that answer.

Steven Karpel - Credit Suisse

Switching over to Blackbeard. It seems like the last couple of weeks have been much more successful in terms of the washing over the pipe. Is there something you're doing different? Are you having more success and encouraged that you'll be able to finish this up?

John Schiller

Yes, We've got that next pipe out of the hole. I would put it out to 50-50 and I think that may be a little higher than that today. As long as we're able to wash over the pipe stand in the middle of the hole, we got good chance to doing recoveries. We went into loss this time. We've all of a sudden stalled out and torked up and the end results of that is we pulled a 4 feet fish out of the hole. So the good news and bad news, that means in a set of the box looking up we can screw back into we're back to piece of tube looking up at us. So now we've got 2 real piece of body looking up at us. That's what slowed us down the last time a little bit. We couldn't get on that fish, when it's just a tube looking up. But each time it's should be different when you're fishing. The key to this thing in my mind is as long as we're washing over and we're able to wash over when the pipe sitting in the center of the hole, we've got a bigger chance to finish recovering. And the closer we get to the bit then the better off we are getting in there with some jaws and being able to pull everything lose.

Unknown Analyst -

Separate question maybe this one's for West to give you a chance to chime in here on capital structure. When you look at the capital structure here, ideally maybe it's in an absolute level on the debt. Obviously, I think there's probably feed John's appetite and maybe do a couple of more acquisitions here and maybe in the calendar year. How do you look at how do you want to fund things going forward and how do acquisition opportunities look?

David Griffin

Yes. So on the capital structure, as I mentioned before, we're a little higher leveraged than where we want to be. We anticipate reducing our debt through cash flow get down below 50% debt to total cap. Obviously, that's going to in the short intermediate term, we really can't be just paying down the revolver. And then a little later stage, as we indicated to previously, we are always looking at opportunities, but we're not planning to do anything until after the June timeframe and probably that means some time this fall, start looking at opportunities. But we're going to continue to pay down debt in the intermediate term. From a financing standpoint, it depends on kind of what you find, if it's a small little pack on deal et cetera, $50 million $100 million or something, we might just do that out of -- on a corporate revolver, we wouldn't do anything really different, maybe if it were significant in some stage we have to actually raise some incremental equity. We don't want to be up at this level of leverage on a long-term basis.

Operator

Our next question comes from Eric Anderson from Hartford Financial.

Eric Anderson - Analyst

Most of my questions have been answered. But just wanted to ask you John, are there any plans to do a follow-up well on Pontiff this year?

John Schiller

This year, could be pretty tight. I think what we'd like to do is get 3 to 6 months of production, see if there's what we're calling the MA-10 sand, which we can tell you for both the production we've seen in the gas sample we have. And from the pressure date is, clearly a separate sand than the original Peterson well produced, which is how we have it correlated. If we see evidence of that sand's a dig, then we could probably 6 to 9 months from now see an updip well. The issue is we need some more td and we're working with McMoran and all to do free day shoot to the North tier. And so it just becomes a matter to you 3D or do you think you have enough base engineering data to support and drilling another well.

Eric Anderson - Analyst

But you're producing now from the bottom sand just right above where you were sidetracking? I know you sidetracked the well and then you said you had to stop?

John Schiller

It's the same sand. We went through that sand and got stuck and then we sidetracked above it and back into it. It's all the same thing on both logs. So in our terminology, the Peterson well is still producing 7 million a day from what we called MA-11. And then, this will all be producing an MA-10, also had a what we called MA-7, which really cut the fault at about 25 feet of pay there.

Eric Anderson - Analyst

So just too early to tell on how you follow-up on that?

John Schiller

Yes. I think you've got to let the well show you how big it is first, when you start seeing something like we did on Peterson, where just to remind you now we float 40 million a day there for 18 months, started with I think 13,400 pounds flowing through in pressure and it slowly fell over that 18 months to about 12,000 pounds, 11,000 pounds. That reservoir has lost a total of 3,500 pounds in the three-plus years we've been producing from it. So it's got a strong water drive component. We need to see that evidence here and then that will start to give us the confidence on how big the reservoir is going uphill.

Eric Anderson - Analyst

Alright. And then also, do you have any further clarity in terms of the plans -- follow-up plans for Blackbeard West?

John Schiller

Yes. I think we will do something at Blackbeard West. My best guess is probably reenter it and go see the Wilcox there like we've seen at Blackbeard East. But I think it's dependent -- there's one of two things. Obviously, we want to get the fish out the hole and drill ahead and see the Wilcox at Blackbeard East. That will give us some good tie in the Blackbeard West and we're to see the Wilcox there. Absent that, if we sidetracked Blackbeard East, we'll probably still see us go through Blackbeard West as a reentry because we've got an update already we got to get to see Wilcox..

Eric Anderson - Analyst

Is is actually the same rig that would be doing both those?

John Schiller

I still don't know that part yet, Eric. The rig situation is a little fluid and that on one of the rigs, either the Coffman or the Mississippi needs to go with Rowan to satisfy a contract of theirs in Saudi Arabia. And so the McMoran guys are kind of moving all around with the rigs, but the rigs are there. I just can't tell you which rigs are going to go on which wells right now.

Operator

Our next question comes from Michael Bodino from Global Hunter Securities.

Michael Bodino - Global Hunter Securities, LLC

A couple of quick questions here. Number one, on Pontiff well, and the question I'll ask is about additional wells. Knowing that offshore Louisiana acreage holdings, did you work interest rate change across this acreage and could you have more exposure to updig flow[ph] or additional sand there?

John Schiller

We're not all sure offshore Louisiana remember that in the body land but we've been, the partnership there has been picking up some additional acreage from the state. We picked up some additional acreage, I think when it's all said and done, you'll see that our acreage position, our net interest increases in the updip direction.

Michael Bodino - Global Hunter Securities, LLC

Any guess as to what percentage or still fluid there?

John Schiller

I would say it significantly increases.

Michael Bodino - Global Hunter Securities, LLC

That being said, moving forward to the EPS, just a quick thought on I know you had covered some of this already, but as you move forward across the year with the seismic, what kind of inventory do think you see nearby in terms of drilling opportunities in the area?

John Schiller

Well, in the first two, I think, we have a total four palm. So we got two more after these. And then, it depends on what you see below the salt, Michael, has a big impact.

Michael Bodino - Global Hunter Securities, LLC

Can you given the fact that the data that everybody is seeing on a sub-salt basis improved so dramatically, are you seeing other opportunities here and there and approach that where to be targeting additional sub salt opportunities in the North[ph} shore?

John Schiller

We have several fields where we're looking at the same thing. Exxon was in the middle of reprocessing two of their fields. We're going to finish that work up. You'll see in New York, you'll see a recurring theme where drilling deeper along some salt interfaces and along where you've had the trap working at every sand we've been paid. You haven't drilled some other sands yet. You're going to see examples like. That's all kind of geared around what you're talking about, reprocess, 3D, we're going to show you kind of what the cost savings have been, but it's pretty remarkable. Our business has always been very intensive computer powered, but what happened with the computer processing speeds and all, we're doing a lot more reprocessing than a lot more iterations, which is able to improve the models that much more for a lot less money than 10 years ago.

Operator

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

Richard Tullis - Capital One Southcoast, Inc.

A couple of follow-ups. That income tax rate for the past quarter, pretty low. Are you're expecting something similar for the rest of the year?

David Griffin

The nine-month effective rate is going to hold for the rest of the fiscal year.

Richard Tullis - Capital One Southcoast, Inc.

And then timing on some of this news related to the ultradeep when do think we'll hear something on Lafitte? Is it still like a July, August timeframe, John?

John Schiller

I think Richard, Jim Bob and I talked yesterday or two days ago about it. We were always pretty heads up with you guys, as soon as we know something, you'll know it. So as we go through the salt weld there and got some pipes set out of there, any sand we see is potential a potential pay sand. If we drill it and we log it and know it's patty, at 22,000 feet, there's no reason not to expect we have an LWD on it. So can start happening in pretty quickly. A matter of getting into the zones.

Richard Tullis - Capital One Southcoast, Inc.

And then just finally, what about the second Davy Jones well, the appraisal well, how quickly do you think you could bring that online following the discovery well?

John Schiller

Richard and Jim Bob talked about that in their call. 6 months is fairly reasonable, if not sooner. It's not the same as what we have on the first well.

John Schiller

Thanks, everybody. We appreciate you joining us today. Look forward to seeing a bunch of you in a couple of weeks in New York City. Thanks.

Operator

Ladies and gentlemen, that does conclude today's conference. You may all disconnect, and have a wonderful day.

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 (Bermuda) Limited's CEO Discusses Q3 2011 Results - Earnings Call Transcript
This Transcript
All Transcripts