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Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

Q1 2012 Earnings Call

October 27, 2011 10:00 am ET

Executives

John Daniel Schiller - Chairman and Chief Executive Officer

Stewart Lawrence - Vice President of Investor Relations and Communications

David West Griffin - Chief Financial Officer

Analysts

Mark Lear - Crédit Suisse AG, Research Division

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Joseph Patrick Magner - Macquarie Research

Yikat Fung

Karanjit Arora

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Brendan D’Souza - Seymour Pierce Limited, Research Division

Steven Karpel - Credit Suisse

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Jeffrey P. Hayden - Rodman & Renshaw, LLC, Research Division

Eric B. Anderson - Hartford Financial Management, Inc.

Michael D. Bodino - Global Hunter Securities, LLC, Research Division

Joseph Bachmann - Howard Weil Incorporated, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Energy XXI First Quarter 2012 Earnings Conference. [Operator Instructions] As a reminder, today's conference is being recorded. I would now like to turn the conference over to your host today, Stewart Lawrence, Vice President, Investor Relations. Please begin.

Stewart Lawrence

Thank you. Welcome to the call, everybody. Presenting today is John Schiller, Chairman, CEO, Founder; as well as West Griffin, Chief Financial Officer. We'll be available [indiscernible] at the end of the call, of course, so we've got other members of the management team here.

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 last Friday 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 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 the latest 10-Q to become better familiar with these risks and our company.

Now I'll turn the call over to John.

John Daniel Schiller

Thank you, Stewart, and good morning, everyone. Our first quarter financial we reported yesterday afternoon. Highlighted in that release were our production volumes rose 57% from last year's first quarter and EBITDA that jumped about almost 150% over the same period, hitting another consecutive all-time high. We kept our production relatively flat with the June quarter and we remain on course to meet our target of 46,000 to 50,000 barrels of oil equivalent day average for the year.

We continue to benefit from strong crude oil realizations associated with our HLS crude. For the month of October, the HLS crude index settled at a $29 per barrel premium to WTI. And for November, that number is going to be north of $26 a barrel. These premium levels are unprecedented. As HLS spread is wide, we've taken opportunity to monetize the majority of our WTI positions and reposition the hedge book using Brent collars. The end result was that we put about $50 million in our pocket in the quarter while repositioning hedges at a much higher price. Our hedge reposition has continued since the end of the quarter, and we put an additional $17 million of hedge gains into the bank during this quarter.

Proceeds from the hedge monetizations add to our continuing free cash flow, which has allowed us to completely pay off the revolver as of last week, far ahead of our goal to do so in March. I repeat, we've paid off the revolver, much in chagrin of our bankers, first time in the history of the company. We cut our net debt-to-total cap from 53% to 47% during the last quarter and continue to drive it down.

I'll have West provide you details on our financials, and I'll get back within a minute. We'll go over our operations and our capital program.

David West Griffin

Thanks, John. Starting with the Davy -- Exxon property acquisition on December 17 through the quarter ended September 30, we had reduced net debt by $270 million. Since that time, we have completely paid off the revolver and build up the cash position, amounting to almost another $59 million in net debt reduction. That's a total of $329 million or 26% of our total debt in just 10 months. Put in another way, it is debt reduction of $3.78 per fully diluted share.

Our $187 million of EBITDA was a new record for Energy XXI, leading to the debt reductions. In addition, we took advantage of the dislocation of WTI prices to our crew. We produced HLS, which historically has closely matched WTI prices. However, since the spring, the correlation between HLS and WTI has broken down. And now Brent has become a better hedge for our HLS crude production.

We repositioned most of our WTI hedges to Brent and got paid $50 million in the September quarter, then locked in a further $17 million on oil and gas hedges in October.

It's important to note that we use hedge accounting and, therefore, do not recognize these hedge monetizations in revenues, income or EBITDA when we lock in the gains. Instead, we will recognize them in the future in our revenue, EBITDA and net income as if the hedges were still in place.

We simply collected the cash upfront. We provide the slide for modeling purposes so that you can see where the associate revenues will show up.

Now let's look at the volumes. Volumes for the quarter were ahead of our internal projection, so our full year volume targets remain intact. During the September quarter, we had a total of about 4 full days of production deferred.

Looking at the quarter on a per BOE basis, it highlights just how well our operations are delivering. First, we increased the oil percentage to 69%, which certainly has an impact on everything else.

Direct LOE came down from the previous quarter and we expect that to continue down since we won't have to pay any of the double staffing issues or overhead charges on the Exxon properties. With lower LOE and strong oil prices, EBITDA climbed to a new record, a whopping $49.79 per BOE.

To provide greater visibility, gathering and transportation cost had been separated out from maintenance and work over cost as many of our peers do. This was never a meaningful number before we bought the Exxon properties, which came with $395 million of pipelines. Now it's a big enough number to state separately.

The bottom line is that we delivered EBITDA that eclipsed the previous quarter's record by 14%. Looking at our net income, we generated $66.3 million before preferred dividends or for the natural gas guidance trying to keep score, that's about $3 per MCF of net income. We've come a long way since we completed the Exxon acquisition.

Our future revenues are well protected by our hedges. This slide reflects our current hedge profile. Using Monday's ending strip prices as the base, this shows the percentages of current production hedge, with which instruments and the resulting net effective prices we would realize that those pricing scenarios came to be. You can see that very little remains in terms of natural gas revenue protection. And again here, you can see that the Brent collars now represent the substantial part of our hedge portfolio. The result is solid downside protection combined with upside potential from rising oil prices.

Also shown on this slide is the percentage of proved developed producing reserves hedge. It is clear that we are essentially fully hedged in oil and almost unhedged on natural gas.

With that, let me turn it back to John for the ops overview.

John Daniel Schiller

Thanks, West. Let's start with a review of the results we've seen to date at South Pass 89 and Grand Isle 16, the first 2 Exxon fields that we've started spending our capital program in.

South Pass 89, we've completed the initial work over campaign. This slide shows that each well exceeded our expectations. Our initial estimate for the recompletion program to have about 2,900 barrels of oil equivalent a day to existing production, which was running at less than 1,000 barrels a day on a gross basis when we took over operation. As you can see, actual initial production rates totaled more than twice that amount, boosting the current gross oil production about 6,000 barrels of oil equivalent a day. This is an example of the type of opportunities we have with Exxon properties, which we believe is repeatable across the asset base.

Grand Isle has also begun delivering similar results. Once we got our rig out there, we were able to recomplete the J-30 and the J-32 wells, and they're currently producing in a combined rate of 700 barrels of oil equivalent a day. We didn't move the rig off the J platforms with the P&Q platforms to do the next 3-way completions. And the P-38, P-27 sidetrack 3 and Q-43 wells were already completed on production, 2,200 barrels of oil equivalent a day. This brings total field gross production up to more than 5,300 barrels of oil a day from the 2,600 barrels of oil equivalent a day that we had when we took over. The rig we were using there was the Rowan EXL 3, and that rig as of this morning is on location to do the Davy Jones #1 completion.

Currently, we just moved the Sundowner 1 platform rig out at Grand Isle -- out to Grand Isle, sorry, to gravel pack the J-21 well. That well throw a 12,000 barrels of oil a day when we did a recompletion earlier through a nongravel pack sands. So we'll gravel pack that well, expect that production on shortly.

We've moved Ensco 99 into the Grand Isle 16 field also to drill a development well named Sunny. This well is targeting 3 sands and are producing in the same reservoir, the C-2, B-2 and B-4 sands, the primary target being C-2. The well has already logged 78 feet of oil in the B-2 and B-4 sands and we should to penetrate the C-2 sand shortly. We anticipate an IP rate of 1,000 barrels of oil equivalent a day starting December, January time frame.

As you can see from our rig schedule, we have a lot of activity beginning very shortly. In fact, during November, we'll achieve a new milestone in terms of rigs running for Energy XXI. As we detailed for you last quarter, our capital program was set at $380 million to $450 million this fiscal year with approximately $175 million going to the Exxon assets.

The next slide shows the list of wells we plan to drill in our core properties in the current program and gives an indication of the depth of our inventory moving forward. The maroon color shows our proved undeveloped -- development wells and the blue signifies our exploration wells. As you can see, the near-term focus is on the development inventory and we would expect future exploration success to replace that development inventory.

Now let's get a quick update on the nonoperated portion of our program, our ultra-deep shelf drill with Jim Bob and the guys at McMoRan.

Davy Jones #1 completion, as I mentioned, the rig moved on location today. Everything there is on schedule, moving according to plan. The facilities have been set. The rig is there. All our equipment is built. We'll go in. We'll start cleaning up the wellbore, and the plugs we left in it and go about completing the well. Everything remains on schedule. We expect to have our 25,000 pounds BOP stack delivered at the end of November and start perforating and producing these wells some time middle to late December.

Over at Blackbeard East, we have gotten into the top of the Sparta Sand, had picked up a 60-foot core barrel and are actually obtaining the core right now in the Sparta Sand. At Lafitte, as McMoRan mentioned with our last call that we lost some additional pay. We were able to obtain sidewalk cores. We'll be analyzing that data and we're going back to drill -- to TD on that well.

At Boudin, we've completed our logging very recently there. We have some large laminated sections that appear to be hydrocarbon-bearing. At this time, we're going to T&A the well, study all the data that we have, including thin section analysis of the sand, and see if the possibility of a completion exists there or not with the technology we know about today.

In the next 3 months, we are going to be drilling. We got the DJ #1 production. We have Lafitte and Blackbeard East both reaching TD. We continue to pick up additional wells to drill -- rigs to drill with our Exxon assets. Our first quarter was one for the record books. We're truly excited about what's following the coming months. Second quarter high volumes and lower cost should continue to drive us to another record for EBITDA, allowing us to continue to reduce the net debt by building our cash position. We'll see our first results from Exxon drilling program and size the drilling of Blackbeard and Lafitte to clear [indiscernible] First production at Davy Jones.

And with that, thank you. And operator, let's open up the call to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Jeb Bachmann with Howard Weil.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Just had a few questions. First, I don't know if you mentioned this, I might have missed it, but what's your current production rate?

John Daniel Schiller

Currently, we're running, Jeb, we have 43 days. We have 45 days. Today's production is 44,000. If you look at October, we're probably similar numbers of what we just reported. If you compare that to our internal numbers on what it takes to get the numbers we're telling you, we're running about over 2,000 barrels that are good right now.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay. And on the mix, do you still expect that to be similar to the first quarter until we get Davy Jones volumes out and it brings cash in? Or what are you looking at for the next quarters on the mix?

John Daniel Schiller

Yes, I think the mix is going to stay in the high '60s until either Davy Jones and/or the Bullfrog wells, some of those wells that we're drilling, they're are high-rate gas wells, we'll obviously skew it a little bit. I don't think they're going -- they're not going to drive us below 64%, 65%, I don't believe.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay, and last one for me. You mentioned back about a month ago on your last update, the last press release, use of the free cash flow you're going to be generating here for the next 2, 3 years. Just wondering if there's any clarity in terms of the stock buyback program or if you've been looking at any kind of acquisitions that might be coming up here.

John Daniel Schiller

Yes, Jeb, we have our annual shareholder meeting in another couple of weeks in Bermuda. And that's one of the things on the topics for our board discussion is what are all our choices of the free cash, what do we want to do with it. And it look that -- we're looking at all possibilities from some tack-on acquisitions that make sense to stock buyback, corporate bonds, et cetera. So West has had to swap his hat now. He has to learn how to manage money..

Operator

Our next question comes from Duane Grubert with Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

John, when you look at that Slide 17 that's got your drilling inventory laid out there. When you look at that today versus looking at that same list a year ago, what had changed in the way you think about what you see there and what did you learn, how is it evolving with your inventories really going to turn out to be?

John Daniel Schiller

Yes, Duane, I mean, a year ago today, we didn't have Exxon. So I would say that, in general, the return of present value on dollars invested is probably 40% or 50% less than what we have with this inventory. I mean, these are strong projects. These projects pay out in less than half a year. So that's the biggest one. As you look at it over the last 6 months, we're continuing to work the economics on a lot of these. And what you see in a few cases is I know some of you look out there and everything we put out there. But the wells you see sliding tend to be gas wells. And their economics just aren't looking that good right now and we don't see any reason -- I mean, we make good money. But relative to spending money for oil wells, it's not really much of a contest. So when you see some movement on there, it tends to be the smaller gas reserve type wells that are taking hits right now and moving further back in the program, so that we could front-end loaded with better-looking oil wells.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay. And then kind of a similar question. When you look at cost control, there's a certain onshore basins that are suffering, mainly on the frac side and so forth, but are you focused on, I'm sure you are, but can you talk as how you're focused on reducing your drilling times and so forth? And again, it's sort of a learning question. What are you improving at that's going to offset any aggressive cost increase?

John Daniel Schiller

There's a little bit of pressure on rig rates, but it's a relative pressure. There's probably 10% move that's available there for them; that's about it right now. What we do, obviously, like the first well at Exxon, we've slammed that well down, well ahead above fee, with the emphasis on team communication, on coordination and making sure everybody's on the same page on how we get these wells drilled quick. And as we drill more wells in each field, that's only going to get better as we pick up our pressure points. A lot of it, beginning about a lot of Exxon wells, there aren't any pipe setting point. We're drilling the wells to TD, coming out of surface pipe. And that helps you do a lot of things, good things. We've done studies on the transportation end between what we're able to do. We combined the Exxon assets and what we've done on our logistics end in terms of coordinating, where we're driving down those costs. And a lot of it is just making sure you work smarter and you don't have boats sitting around with nothing to do, et cetera.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

And finally, and maybe this is more for McMoRan, but what input do you guys have on calibrating the logs, for example on Lafitte. You are logging this well in a new area, a new zone. What do you do to make sure that the scribbly lines really mean something to you?

John Daniel Schiller

Well, look, we both have very technically savvy staffs. They visit with each other. We're talking while the wells are logging. We're discussing what we're seeing. So I think the end product we're getting is as good as anyone would expect. And clearly, Duane, what I've seen over the last 2 years now is the service guys are continuing to deliver on the tools. So the log-ons we just made at Lafitte went off without hitches, and we couldn't have done that 2 years ago. So the tools are getting built, they're delivering results. We've drawn behind pipe, pole neutral logs, now that can handle the temperature and pressure. They weren't there 2 years ago. And we are doing a lot of neat stuff on Lafitte to date so that we have some base parameters to tell us what we have in case we ever find ourselves in a bind where we have to set pipe and log through pipe rather than open hole. We know what those logs are going to look like now. So we're making a lot of headwinds, a lot of correlation. I mean, coordination between the companies.

Operator

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

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

John, looking at the production guidance for the full year, I guess you guys have to average around 47,000, 48,000 barrels a day for the rest of the year. I mean, how do you see that ramp up playing out?

John Daniel Schiller

Yes, I mean, obviously, look at the rig schedule. We start drilling a lot of wells and they start coming online end of this year, early next year. So what you really see is a quarter where we're probably going to have some growth this quarter. But you really see the ramp up occur in the third and fourth quarters, and you're talking extra rates, they're in the high 50,000.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

For fiscal year '12?

John Daniel Schiller

Yes.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. And how much Davy Jones production is in the 46,000 to 50,000 barrels a day?

John Daniel Schiller

Less than 1,000 barrels.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Less than 1,000?

John Daniel Schiller

Yes.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. The CapEx for the full year, how do you see that playing out for the rest of the year? I know you had about $117 million for the first quarter. It should be pretty evenly spread or just back half weighted?

John Daniel Schiller

Yes. I mean, this quarter is not going to be a lot more than that, it will be fairly close. And they will start seeing the third quarter get bigger. I think the big deal for us is going to be, as we go into the fourth quarter, you've heard us talk about we paid $600 million, all things being equal, is the sort of optimum level that we need to be spending CapEx at. And I think if all stays where -- bottom $90 a barrel and the Exxon wells are delivering the way we expect the results to deliver, then I think what you could see us do with the last few months of the year rather than drop rigs, which is what we show on that drill schedule, we'll probably keep those rigs and accelerate some of the fiscal year 2013 and the fiscal year 2012 drilling so that we don't drop rigs and not be able to get them back. And so if all that happens and things are going good and all stays above $90 a brand et cetera, the budget could creep up to 500. But that's sort of a situation where everything is going really good.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

I mean, would that be your preference now that you have your revolver paid down, that you start using excess cash to accelerate drilling as opposed to maybe buying back stock or other options?

John Daniel Schiller

Yes. I mean, I think as long as -- Again, as long as wells come in the way, we think we're drilling with the cost we think that we're bringing on 1000-, 2000-barrel-a-day wells one after another. Nothing we can do can compete with what that capital return is because we're talking less than 6 months payout on everything.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

And just finally for me, West, what are you expecting for interest expense for this current quarter?

David West Griffin

This next quarter?

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Yes.

David West Griffin

It's relatively straightforward. All we have outstanding are the 2 extensive bonds, $750 million at 9 1/4% and then $250 million at 7 1/4% [ph]. And we'll have a tiny little bit of interest income associated with the cash that we have on the balance sheet that should largely offset some various bank fees and stuff like that.

Operator

Our next question comes from Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Just 1 follow-up question on the drilling inventory. You had mentioned likely calling in some of these -- some oil projects ahead of some gas projects. But also just comparing it with recent presentations, it looks like you are targeting even a little bit more exploratory wells in 2013 and '14. What's driving some of that decision? Is it just the oil versus gas split?

John Daniel Schiller

Yes, I don't think I even said that. I think we've continued the rework inventory. We continued to evaluate all of the opportunities we have. And as I've said, we started with a list that basically was driven by Exxon's works. And as we go through it, we start putting our work to it, we start seeing things a little bit differently, maybe the size, maybe the risk profile, et cetera, changes. So we move some things around.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And can you give us just an update in terms of Bullfrog, the well is drilling right now just in the sense of timing, how much longer do you think you have to go on that well?

John Daniel Schiller

Which well, I'm sorry I missed?

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Bullfrog.

John Daniel Schiller

Bullfrog. Let's just say that drilling a 55-degree hole at 18,000 feet has caused us some issues. We've stocked the pipe. We didn't get the line to the bottom and we start pipe. So we're going to process the sidetrack in that well. We should be there in 30 days. We've been within 1,000 feet of the reservoir with Schlumberger sizing while drilling. We feel very good [indiscernible] to there that we're up depth to the offset well. We just got to get the well drilled.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then just with ultra-deep, can you walk through a 3- to 6-month time frame from flow test to actual hookup through the facility to the Davy Jones #2, major steps involved? And then when you talk to McMoRan about even Davy Jones, but just the ultra-deep in general, how are you thinking of approaching the development program with additional wells at Davy Jones? At what point will you start really accelerating some development drilling?

John Daniel Schiller

Yes, I mean, somehow, we don't seem to be doing a very good job communicating on Davy Jones commercial production. But all the big stuff has already been done. The facilities are there. The gas exchanger for cooling the fluids is there, heat exchanger. So when we have this well up, it's going to be very similar to what we did at the Pontiff's bound time well at Laphroaig. We're going to flow this well through a test barge facility. But once we get the flow test, all we're going to do is turn around and replummet the other way. So we should have commercial production within 1 month of the flow test at the latest, and the facility is already there. And we can have the Davy Jones too. A couple of things there. We've had to order different drillers and Schlumberger is redesigning a gun because we're perforating bigger pipe than Davy Jones #1. So that's going to push that probably to late summer, early fall. But similar deal, we'll build a small [indiscernible] there. We'll put an exchanger on it. And that production will flow right back to the facilities that are already in the water. With regards to the development plan itself, I think we want to watch the first well. We want to get some sense of what it's doing. I think the next well we drill will be north to Davy Jones somewhere with 2 or 3 prospects there. All of them are in the process of getting permitted. I think we'll go drill one of those. And then I think we come back and start the development program 6 months after production or a year, some of that's going to be dependent on rigs.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then lastly just with Blackbeard East, it sounds like you're in the Sparta Sands. What's the time frame to get through the Sparta and down to the Tuscaloosa potential? I know that's one of the hardest questions because it's not easy to give an in depth, but...

John Daniel Schiller

I know. We're not going through Tuscaloosa. That's easy one to answer. We'll get this core knocked up probably today, the true pit out of the hole probably 4 to 5 days. We'll go back in there and drill again for probably a week and we should be through the Sparta Sand. And I will expect that we probably make a log at that time. So 3 weeks, 4 weeks, before Thanksgiving we should know what we have there and then we see where we go from there.

Operator

Our next question comes from Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

I was curious, could you, I guess, rank in terms of just the percent of available capacity on the platform is there for Main Pass, Grand Isle, South Pass, et cetera? Is it fair to assume that Grand Isle and the South Pass have the most capacity in terms of -- that you could bring additional wells on into or...

John Daniel Schiller

Capacity -- in terms of just how much facility of capacity we have?

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Yes. This would be a water-handling capacity or ore-handling capacity or gas lift capacity, how are you guys are kind of constraining these properties, just to get a sense of how much extra runner you have if you start bringing on the wells?

John Daniel Schiller

I got a lot of guys at the table shaking their head, which I believe means these facilities were so big and the fields so large. You look at the cubes on these fields, 200, 300, 400 million barrels of oil that, that's not something we're worried about on any of these fields. As a company, the Main Pass 61 area is where we probably push the most through the facilities and 1 or 2 platforms at South Tim 21 where we're really cleaning things up and drilling new well and have a lot of water we're pushing it. But on the Exxon assets, we've got a lot of running room. That's not even in the top 5 concerns in most of ours in terms of what can keep us from growing production.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. Good deal then. So probably then from -- that would keep LOE then kind of trending down on a unit basis as we go forward?

John Daniel Schiller

Exactly.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Cool. And then speaking of Valentine Pontiff, what is -- how does that well still doing? Do you guys have a rate on that you can disclose?

John Daniel Schiller

Pontiff is still 44 million a day.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. Great. And then the last one is just more on an issue [ph] there for West. The G&A spread this quarter was a little more evenly spread between stock-based comp and straight G&A. Should we assume that going forward is sort of split or should we go back to the split we had kind of the last prior 2 quarters?

David West Griffin

I mean, that's an excellent question. One of the biggest challenges we have associated with the G&A is that we do have stock-based comp, which is based -- which obviously goes up and down the paint [ph] with what happens with the stock price. We had a stock price at the end of the quarter was about $21. We're setting that stock price today about $30. So that's going to -- assuming the stock price continues to get up, well, a little higher is going to be a little heavier with respect to stock-based compensation associated with this next quarter.

John Daniel Schiller

Andrew, you're talking about [indiscernible] Which usually gets us in trouble. But can we give them the A part of A times B equals C for tax LNG in the stock part? I mean, it's a set number, isn't it? Andrew, we'll look at, kind of sure then [ph] forgot somewhere against something on the web that kind of give you some sense or a ballpark number to multiply by the stock price had been every quarter so that, that's not a complete surprise to you. You got to be aware, at least, put you in the ballpark on it.

Operator

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

Michael D. Bodino - Global Hunter Securities, LLC, Research Division

Just a couple of follow-ups for West and then an exploratory question. And I may have missed what's going on this morning. But could you comment, West, on the corporate income tax rate? It was a little bit lower than we expected. And just some guidance for the rest of the year how this is going to evolve?

David West Griffin

Sure. We have -- first of all, as you know, we don't pay any cash taxes. So what I'm talking about is for book purposes what the effective tax rate is, and right now that's about 11%. And that is reflective of a full year forecast where we anticipate ending up for the year in terms of net income.

Michael D. Bodino - Global Hunter Securities, LLC, Research Division

So we can be pretty consistent about that level going for the rest [ph] of this fiscal year?

David West Griffin

Yes, that's our best estimate for the full year.

Michael D. Bodino - Global Hunter Securities, LLC, Research Division

Very good. Okay. More -- now more important, relative to the drilling program for the balance of the year, John, looking at the forecast that's out there and I know you made a comment about if things were successful, likely to see the rigs playing action in through the fourth fiscal quarter. On the schedule there, there's not a whole lot of exploration wells, in Bullfrog and Golden Bear [indiscernible]. Looking into the fourth quarter pending success, would you do more exploration to [indiscernible] success more development? How do you think about that?

John Daniel Schiller

We tend to put a lot of emphasis on just the present day gain we get for every dollar invested. So we risk the exploration wells. They have to hang in there pretty good to capture dollars. Obviously, we want to drill some exploration wells. So we work on making that happen. And given the fair balance on our portfolio so that we're always creating additional inventory for the company. And that's kind of why you see these things changing. We've got the assets in. It's been almost 1 year now. We've been over them and through them. We're looking at things and we're kind of repositioning a well here and a well there to give us a nice balance, high dollar return on dollar invested portfolio.

Michael D. Bodino - Global Hunter Securities, LLC, Research Division

You end up having [indiscernible] you've had with the Pontiff well, Ashton, Onyx, some of those [indiscernible] that really had fast payouts, very good returns. Assuming that there is no land issues or lease issues, do you see further exploratory opportunities in terms of being de-risked with those successes in those areas or similar type exploration opportunities?

John Daniel Schiller

Yes. I mean, some of those, obviously, development wells. And since you brought up Onyx, I'd tell you it's still making 2,200 barrels of oil a day for 4 straight months. So you can do the math, that's a hell of lot of cash flow from 1 well. The beauty we have, Michael, you always going to keep in mind is all of this 90% of the exploration we're talking about sell BOP production. So we're not going to run out there. We are moving the ball forward everywhere, Laphroaig, that area we've just tell you what the wells do. And I think over the next 6 months, we'll get some more data. We're probably going to build up in there. Usually, we have to shut in for some reason. We'll get us some buildup. We'll get us some size at how big the reservoir is. Right now, it's certainly performing extremely nice. And then we'll put all that together and figure out where we go next.

David West Griffin

If you look at the schedule, you'll see we don't see a Pontiff well until 2013.

Operator

Our next question comes from Jeremy Porter with Seymour Pierce.

Brendan D’Souza - Seymour Pierce Limited, Research Division

Actually, it's Brendan D'Souza at Seymour Pierce. Jeremy is with me. Just 2 quick things. One is what kind of a production rate will we see in the second quarter of the year on an average? Will it be about 44,000 to 45,000?

John Daniel Schiller

Yes. I think for the quarter it's going to be probably a little bit more than this, 41,000 to 41,500, 42,000 range at best. It will go out December at about 44,000. And Jeremy (sic) [Brendan], that's -- as we move these rigs around, as we do we rig work, we take some shut in time, so I'd tell you we make 44,000 barrels a day. Today is a good day. We didn't have a lot of production shut in. But when we shut in production, we have some high 30 days that keep in the average in there.

Brendan D’Souza - Seymour Pierce Limited, Research Division

Okay. And the other one is just come to the recompletion program, you guys seem to be very successful. On the Grand Isle one, the 16 and the 18 one, you guys have done 4,200 initial production. What was the production before this for these 5 wells?

John Daniel Schiller

Grand Isle production was around 100 barrels a day, I believe.

Brendan D’Souza - Seymour Pierce Limited, Research Division

A well?

John Daniel Schiller

Know those wells aren't on production, so that's all pretty 0, sorry.

Operator

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

Jeffrey P. Hayden - Rodman & Renshaw, LLC, Research Division

Just a follow-up for me on Andrew's question, jumping back to the G&A for a sec. It looks like the cash G&A in the quarter was maybe about $10.5 million. Is that a good number to be using going forward, the run rate or is that a little bit anomalous in the quarter?

John Daniel Schiller

I'm going to let West here with the details. You got to remember where our fiscal year June 30 end of the year. So our bonuses, our performance unit payouts, all of that occurs in this quarter. So that's why you're seeing a G&A bump this quarter. It's all our payout at the end of our year. They're shown in the proxy, obviously, that we have out there. So you should see a lower number going forward. And that's what I was telling you. We're looking at some way to give you a little bit better guidance, Jeff. We can tell you how much we need to accrue around restricted shares and the performance unit based on a different stock price where you guys can just build a ratio on it. And then our fixed piece is pretty straightforward. What you saw this quarter, the next quarter is not going to be very much for that.

Jeffrey P. Hayden - Rodman & Renshaw, LLC, Research Division

Okay. So that kind of $10.5 million number is sort of a good number to use as kind of a baseline excluding any of the kind of stock option, depreciation, right, et cetera?

John Daniel Schiller

Yes.

Operator

Our next question comes from Mark Lear of Credit Suisse.

Mark Lear - Crédit Suisse AG, Research Division

Looking at the ramp coming in end of the year on the production, just speaking about what kind of pace declines you're assuming on your current production?

John Daniel Schiller

I mean, we've talked about this in the past. We'll see what we're bringing on from behind pipe, which cost us very little money. We're somewhere between 5% and 15% decline on our base production levels. And that's really what we have to overcome with our CapEx program. And that's a little bit different than a lot of our peers because the oil declines in general, particularly on your long-term wells, that have been on production along shallower than what you'll typically see from a gas well, it's making 320 million a day in the water here until it's gone.

Mark Lear - Crédit Suisse AG, Research Division

Got you. So then, what kind of maintenance CapEx levels will keep you flat?

John Daniel Schiller

We took a hard look at all this in the last month when prices were doing what they're doing. And our maintenance CapEx at around 42,000 barrels a day is between $160 million and $180 million of capital. Along those same lines, we took a look at what happens if all came crashing down in the next month to below 70, what would you do and our CapEx been probably just below $300 million for the year in that case. We don't really commit anything long term, Mark. We've got 1 rig that was hard to get that we have for about 6 months for 4 wells. Other than that, most of our rig contracts are 1 or 2 wells at a time with options.

Mark Lear - Crédit Suisse AG, Research Division

Got you. And then, I guess, just turning quickly to realizations, you're definitely seeing a good premium versus WTI. But I guess realizations in the quarter were still below HLS. On a go forward, should you be capturing more of that spread?

John Daniel Schiller

Yes. I can't remember if we showed the slide in here or not. But our physical hedge slide that's out there, we've got 10,000 and 12,000 barrels a day physically hedged through December. Hold on a minute. Yes, 10,000 barrels a day for November and December, 12,000 in October. Those are hedged at roughly on an average $10 a barrel premium. After that, all of those are all. So you'll still see a little bit of impact this quarter and then after this, you should be seeing the full benefit everywhere.

Operator

Our next question comes from Joe Magner with Macquarie.

Joseph Patrick Magner - Macquarie Research

Most of them were answered. I guess 1 that might have been missed earlier. I know you're assessing use of the free cash flow. But are there any acquisitions out in the marketplace right now that look attractive or that might present an opportunity should you decide to pursue anything?

John Daniel Schiller

Yes, I mean, there's a few, Joe, that -- we look at everything. Obviously, you guys have seen what's out there. You heard what's out there, but we look at different opportunities. We have to really like it to be aggressive. So we look at something out today. We made a bid and the feedback we got is we were 25% below the market, and we're very comfortable being down on that asset. It wasn't a game changer. And we're talking less than a couple hundred million dollars sort of number, things that we can put on the revolver. There are no big packages out there. Obviously, the stuff going on with El Paso, it will be of interest from our joint venture side of life where we go against some blow-down gas assets. It's not something we would put into the public company. And there's some other -- there's some deals from some majors that are different than we're going to look at. Some will involve drill opportunities. Some will involve production. So we'll look at some of that. As I've said many times, it is not dominating us. It's tough to keep West to be calm because he loves making deals, but as I've told him, he now has the most boring job in oil field, well-run company's CFO, you get bored quickly. So we look at everything, but we're not out there aggressively looking to do a deal. We like the inventory base we have. We feel very comfortable that we post double-digit organic growth gains off over the next 3 to 5 years. So the right deal comes, and if it hits us and it hits us squarely in our synergy pipe, we'll do it. But we're not going to bid aggressively for things that are just nice to have, but don't really change the picture for us.

Joseph Patrick Magner - Macquarie Research

Okay. And then, I guess, the [indiscernible] organizationally, where are you now with respect to manage the property base? Are you still looking to add people? Do you feel like you're in a pretty good position to operate what you've got?

John Daniel Schiller

Yes. We've actually got the staff where we wanted now. We've staffed all of our exploitation teams. There are some things we probably still want to do on a more region-wide level, where we actually take a few people and dedicate them [indiscernible] big picture original type things [indiscernible] jumped in one on one for a lot of you. That's not something you typically see independents do. That's the reason that the Chevrons of the world probably have a better understanding on the overall deep world [ph] play because they have this incredible amount of data and they have an entire group that that's all they do is try and tie it altogether. We can't afford things like that in our G&A. But we are going to do a little bit to where we have some guys are focused just on that type of stuff. And that's really the only thing we haven't filled for now.

Joseph Patrick Magner - Macquarie Research

Okay. And then on exploration front, be clear off exploration front. I guess just to be clear and maybe there's a clarity right now because it sounds like some things aren't permanent. But what's the go-forward near-term plan beyond Blackbeard, Lafitte and the work being done on the Davy Jones? Have there been any specific decisions made on what will be drilled in that program next year? Is that still to be determined?

John Daniel Schiller

Yes, I thought it was pretty clear when I said it will be 1 or 3 to 4 wells.

Joseph Patrick Magner - Macquarie Research

Obviously you didn't identify which of those -- what that sort of list of 3 to 4 wells -- what names are you having [ph] right now?

John Daniel Schiller

No, I mean, we've got a lot of -- McMoRan's passport permits on several wells. I will tell you that the most likely next well to spud is a Blackbeard West shallow prospect. We need to spud that well before the end of November. So that's going to be the next well. It's not anywhere near as deep. We still call it ultra-deep because we drill below the salt well. And if you'll remember the shallow pace we saw at Blackbeard East right below the salt well like at 19,000 feet and we've kind of told you guys that, that sets up several more plays, where what we are interpreting as salt now appears to be some gas trapped amplitudes in some of the areas. So that's what Blackbeard West is. We have a setup like that where we think we can get some gas at 22 -- what's the [indiscernible] in between -- 20,000, somewhere around there. So that's the next well, for sure. It's not a Wilcox or a Blackbeard East deep-type drilling. It's a little bit shallower. I would think the next well after that will be when one other areas, north of Davy Jones, John Paul Jones, England, one of those big structures north of Davy Jones, et cetera.

Operator

Our next question comes from Brian Kuzma with Weiss.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

I just had 1 question in regards to the Lighthouse Bayou well that Armstrong's drilling. I'm just wondering are there -- I know it's a little bit further west to the play concept that you guys are generally going forward. I'm curious if there are any implications or there's any legacy that you guys have on shore that continued as a lateral to the play concept there going forward?

John Daniel Schiller

Yes. I mean, Brian, clearly now, we've told you all that the lease position we kept we felt was better quality sands and at the same quality and temperature, the same quality that generated to the west and the temperature got hotter. Now that said, Chevron has been out there and publicly said in speeches that they understand all that. They still think there's plenty of sand quality to make the projects work. And as I alluded to earlier, they have a hell of a lot more regional data and log penetration points than we do. What we've also said though is that, look, I promise you, I'm reading for Welch and Armstrong and the Chevron guy 100% on the well, want them to have a discovery. All it does is expand the trend. It gives us more information and more knowledge getting to be added on the sands. And I do think there are plays onshore that make sense and that we'll continue to look at opportunities involving some of them.

Brian L. Kuzma - Weiss Multi-Strategy Advisers, LLC

Going forward, it's kind of something that you guys will look to maybe buy your way into or something like that rather than a legacy acreage position, is that right?

John Daniel Schiller

Yes. I think it'll be acquired, to go lease land and things like that as opposed to do we have some acreage that it's sitting under right now, yes.

Operator

Our next question comes from Karanjit Arora with Columbus Hill.

Karanjit Arora

Just a quick question on current production, I think I've missed this, and if you can sort of walk through what sort of causing the shut-ins that's preventing realization of sort of the run rate?

John Daniel Schiller

Yes, I mean, today, for instance we did -- just a little bit over 44,000. October, we are averaging right in line with what we've done this quarter. That's a couple of thousand barrels a day ahead of our budget and our budget is the number that we keep giving you guys, the 46,000 to 50,000 barrels a day forecast for the year. What caused the shut-ins are everything from every platform that you have a rig on, there's certain things when we want casing, for instance, where we're required to shut in the whole platform. On the Exxon assets, in general, there's a lot of old compression out there, some of them were serial numbers 1, 2 and 7. So when they go down, we have the machine parts for them. You can't call the parts supplier and get them delivered. What you'll see us do over the next few years is get these assets the same way we got the rest of our assets, which is least compression with guaranteed 95% run time. The problem as you might guess is when you take up the compressor, you're shutting the whole field in for 1, 2 or 3 weeks, depending on how big a lift it is and what you have to do to get the new one up. So obviously right now with prices where they are and all, we're going to keep patching up and getting things to go as long as we can. We've also been doing some meter work so that we have a better sense of the allocations, all of the Exxon assets for the most parts, the oil flows into Grand Isle Central facility, which is onshore on the island there. And so we want to make sure we understand where it's coming from. And when we tell you we bring on 1000-barrel-a-day well at South Tim 54, we actually see 1000-barrel-a-day gain because we're testing the well. And so Exxon didn't worry about that kind of detail. We do. It's 1 of the things that allows us to really get down and worry about our cost and all. So all of those things impact volumes. Any time you're fabricating, you're doing midfacility work, you're shutting in platforms. There's negatives and positives to a platform rig when you're doing to do a lot of work like we're going to do at West Delta with the platform rig. It's a lot cheaper, but we're here doing all the loads and there could be 20 lifts. To put one of these rigs on a platform, you'll shut in your production. So you might take 3 to 7 days of production downtime to get a platform rig loaded, but then you got to save a lot of money on the CapEx side of the rig cost. And that rig is going to be there for the next 6 months. So it's work to get right now. And so all of those things are going on at any given time, plus, yes, you've heard us talking about, the infrastructure in the Gulf is not young. So this quarter with Sea Robin that said they were going to shut in for 10 days, ended up being 17 days of shut-in time that affected East Cameron production. And those are the things we deal with day in and day out. But the production doesn't go anywhere. It's there. It just shows up as a curtail for that day.

Karanjit Arora

Got it. And you guys are factoring this into your guidance, I assume?

John Daniel Schiller

Yes, sir.

Operator

Our next question comes from Eric Anderson of Hartford.

Eric B. Anderson - Hartford Financial Management, Inc.

Most of my questions were answered. But 1 thing I want to ask about, John, is back when you're drilling Blackbeard East, before you got the pipe stuck, were you able to ever get a core out of the Sparta?

John Daniel Schiller

No. We drilled through the Sparta. We had a mud log show. We had indication that we had 200 for the sand as thick -- the same thickness at the Sparta is over the Davy Jones, more than 2. And we're actually in the process of coming out the log of well when we got stuck and lost the mud in another wellbore. So that's 1 of the reasons. You've been with us a long time. You go back to Davy Jones #1. Remember we had logged a bunch of sands and so we ran a core, but all in there blind, thinking we were still going to be in the sand and all we ended up logging was -- I mean core, was a bunch of siltstone. We really never got into the main sands. So here, because we had already been through the interval, we had a pretty good sense where the top was. As soon as we drilled in to what we thought was the top where we circulated up and we saw the sand. We stopped drilling and picked up, came out of the hole, picked up the core barrel. So we should have a pretty good core here. It's one of those rare opportunities on an exploration where you knew where you were to get some core data.

Eric B. Anderson - Hartford Financial Management, Inc.

You said I think previously that the Sparta Sands here are a lot more clean than they are at Davy Jones #1 or $2?

John Daniel Schiller

Okay. For what you can get off of mud logs, start with that caveat, the quality of the sand here is a better sand than we saw in the Davy Jones area. And the quality of the mud log show itself is better. We didn't even have mud log shows at Davy Jones #1 or #2.

Eric B. Anderson - Hartford Financial Management, Inc.

And how was sort of the well control issues been going now compared to back when you had the issue, have you done things differently, this gone slower, higher mud rates or [indiscernible]?

John Daniel Schiller

I'm sure we get all the pressures and we're starting on a little bit of that with some of the stuff we saw in Lafitte. But what we've been doing is making sure we'll come out of the hole that we set a heavyweight pill that basically approximates the weight of the mud that you have while you're drilling and putting pump pressure against your formation. So it's slow and steady. It puts us in a position courtesy of our government requiring us to function test to be a piece every 7 days, whereas pre-Macondo we would be drilling 10 or 11 out of 14 days. Today, if we make 6 or 7 days, it was a good 2-week period because the precautions we take to make sure there's not a blowout and because the government insisted on function testing to be a piece every 7 days.

Eric B. Anderson - Hartford Financial Management, Inc.

And my final question is how do you feel sort of big picture about Lafitte at this point relative to what your expectations and thoughts were before you started drilling it?

John Daniel Schiller

I think we still feel everybody is optimistic before we started drilling it. We're seeing laminated sands. We're seeing gas hydrocarbons, so we know we have a trap that's working. What we need to see is a big, big sand. When you look at what the Paleo is telling us and what age we're in, we feel very comfortable that we're still in Lower Miocene interval and we're going to see sands. And if our; seismic correlations are right, we're going to end up seeing the same Frio Sands that we saw in Blackbeard East, at 30,500 at Blackbeard East. We ought to assume around 30,000 over here and we think they're thicker. So we're cautiously optimistic drilling ahead and see waiting to get another sand log and see what we see.

Eric B. Anderson - Hartford Financial Management, Inc.

Okay. And if I could just follow up on Ron Mills's question about the back to Blackbeard East, assuming you get to the 34,000-foot level, will that get you into sort of the Wilcox or is that sort of squarely in the Sparta?

John Daniel Schiller

It will get us into the Wilcox space. The Sparta being where it is, at whether Wilcox 2, 3, 4 sands, come in relative to that, we should be clearly into the Wilcox Sands at that depth. We shouldn't make Tuscaloosa.

Operator

Our next question comes from Steve Karpel with Credit Suisse.

Steven Karpel - Credit Suisse

I hope I didn't miss this. I just want to understand why it's done on the debt side, given where your rating is now, kind of what the conversations are with the agencies, specifically, obviously, Moody's, obviously with this huge debt pay down. And then secondly, kind of how do you look at and how do they look, you talked about acquisitions, but whether the tuck-ins are a little bit bigger, kind of how you plan to pay for those upfront, obviously, the cash flow on the back end to pay off any debt piece there?

David West Griffin

I mean, got what we've done with all the rating agencies, we've obviously kept them up to date. Moody's, our frustration has always been that they tend to be sort of balanced sort of guys, so they look at things like debt could be [indiscernible] or approved at all, et cetera, but all [indiscernible] are created equal. So they use the 6:1 ratio irrespective to whether or not it's a GAAP barrel and you're really not making money off of it versus the oil barrel. And so that's sort of our frustration with their approach. As we've indicated in the past, we've achieved our first goal after the Exxon acquisition, we want to get our debt total capital below 50% we've achieved that. We can further provided some guidance that we want to trend down to about 40% debt to total cap. Obviously, we're well on our way towards achieving that objective. And we've also indicated that to the extent that [indiscernible] of acquisition that we put a little bit value [ph] et cetera that we wouldn't hesitate to leverage up a little bit. But we want to stay below 50% debt to total cap. So what you'll see us continue to do here is pay down some debt, et cetera, to the extent that we find an acquisition of reasonable size. At some point, it's $100 million, $300 million or something like that. We just write a check for it.

Steven Karpel - Credit Suisse

And obviously, you're going to come up a couple of times with kind of the dividend side, how do you look at the dividend?

David West Griffin

We looked at dividends in the past. We actually had one, as you know, at the end of 2009, we, I think March [indiscernible] of 2009 was our last dividend. And it's a subject for continued discussion at the board. That's one of the things that we'll be talking to the board in our November board meeting.

Operator

Our next question comes from Yikat Fung with Jefferies & Company.

Yikat Fung

I was just wondering going into the December flow test at Davy Jones #1, could you remind us what your expectations are for initial production from that well?

John Daniel Schiller

Sure. I think anything over 45 million, 50 million a day is outstanding. We're looking for something between that and 75 million a day, which is our tubing limit. I'm going to be looking a lot more at indications of size, how strong and stable our flowing tubing pressures and necessary rate, rate all function at [indiscernible] fixed rate with opening up more reservoirs. So I just want to see that the reservoirs are big and draining and that we have stabilized flow rates.

Yikat Fung

And do you have kind of an expectation of when that production will start to decline?

John Daniel Schiller

We have different models. What I would tell you, in general, is for these type wells, you look at Laphroaig, the Peterson, the Pontiff, big high-pressure, abnormal pressure gas wells. We're going to make somewhere between 60% to 75% of the reserves on a flat life. So if the recovery is going to be 100 Bs a well, then you take 75 Bs, divide it by 75 men a day and that's 1,000 days flat line. So we're looking at 2.5, 3 years sort of flat line, which is consistent with all the big wells we've all done in our career.

Operator

I'm not showing any other questions in the queue at this time, gentlemen.

John Daniel Schiller

Thanks, everybody, for joining us. We'll get back to you if we have some something to talk about on the big wells, obviously. And in the meantime, we are going to keep churning out the cash flow and growing our oil production. So see you out there on the streets. Bye-bye.

John Daniel Schiller

Thank you. Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the conference. You may now disconnect. Good day.

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