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Energy XXI (Bermuda) Limited (EXXI)

Q4 2011 Earnings Call

August 11, 2011 10:00 am ET

Executives

Nelson Steve -

Stewart Lawrence - Vice President of Investor Relations and Communications

Unknown Executive -

David Griffin - Chief Financial Officer

John Schiller - Chairman and Chief Executive Officer

Analysts

Andrew Coleman

Biju Perincheril - Jefferies & Company, Inc.

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

James Silcock

David Magruder - Knighthead Capital Management

Duane Grubert - Susquehanna Financial Group, LLLP

Jeffrey Hayden - Rodman & Renshaw, LLC

Richard Tullis - Capital One Southcoast, Inc.

Nicholas Pope - Dahlman Rose & Company, LLC

Operator

Ladies and gentlemen, good day. At this time, I'd like to welcome everyone to the Energy XXI Fourth Quarter and Fiscal 2011 Year End 2011 Earnings Conference Call. [Operator Instructions] Today's conference is being recorded. And now I would like to turn the call over to Stewart Lawrence, Vice President of Investor Relations. Please go ahead, sir.

Stewart Lawrence

Thank you, Mary. Welcome to the call today, everybody. Presenting today is John Schiller, Chairman and CEO; and West Griffin, Chief Financial Officer. We've also got other members of the management committee in the room. They'll help answer the questions after we're done with the formal part of the call.

Before we get started today, 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 night and in our public filings. We disclaim any obligation to update these forward-looking statements.

While the company believe 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, when it's filed early next week, 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 Schiller

Thanks, Stewart. Good morning, everyone. Our audited financials were reported yesterday afternoon. Highlighted in that release were production volumes that were up 59% on an annual basis, 66% quarter-on-quarter, with a June 30 exit rate that was up 74% from the prior year. All of those are record levels for the company.

Reserves are up 54% to a record 117 million barrels of oil equivalent. We replaced 124% of our production organically, which was pretty darn good for an acquiring and exploring company. Of course, the bulk of our growth came from the December 17 acquisition of the ExxonMobil properties, which made Energy XXI the third largest oil producer in the Gulf of Mexico shelf.

We continued our history of positive performance based reserve revisions. We sold 8 million barrels of low value onshore gas properties at the end of June that cannot capture capital internally given the much better opportunities we see on the ExxonMobil properties. The bottom line is we not only grew the reserve base by more than $0.50 but we high-graded the quality of those reserves.

The purchase of the oil-focused Exxon properties fields and sale of our onshore gas fields put us back in the lead of our peer group in terms of oil. Our reserves are now 66% crude, 34% gas. Our crude sells at a premium to WTI. In the June quarter, we averaged $109.30 per barrel pre-hedged for our crude compared with the WTI price of $101.36, right at an $8 a barrel premium.

Our oil-focused production drove adjusted EBITDA up 78% for the year and 111% for the quarter. Free cash flow continued to strengthen our balance sheet as we reduced net debt by more than $200 million since the December 17 acquisition. For the year, debt to total capitalization was reduced from 64% to 54%.

In the past 3 months, we've brought on an excess of 7,000 barrels of oil equivalent a day net for the company. Of these volumes, less than 700 barrels of oil per day were included in our reported volumes for this quarter. We continue to be ecstatic over the opportunity set associated with our latest acquisitions.

Every well we've worked on has exceeded our expectations often by 2 and 3 folds. We've had 2 wells that we expected to be gas turned out to be oil producers. Every day, we're identifying new opportunities from behind pipe recompletions to fixing simple hole-in tubings. All of these results are very economical uplift for production. The Exxon properties will continue to fuel our growth for years to come.

Let's have West provide the details on our financials. Then, I'll talk about operations and our capital program. West?

David Griffin

Thanks, John. Before getting into the details, let's step back and look at the big picture for the past year. During fiscal year 2011, we made several moves to improve both the liquidity of the company and to reduce our cost of capital. Beginning in October and November, we moved to strengthen the balance sheet ahead of the ExxonMobil acquisitions. When all was said and done, we eliminated 2 high-cost debt issues and most of the convertible issue and replaced them with lower coupon and longer-term issues. Then as John mentioned, we used free cash flow since the December acquisition to pay down over $200 million in net debt.

The benefits of all these achievements clearly showed up in the stock price. It's worth keeping in mind that all else being equal, every dollar we continue to pay down with free cash flow accrues to the shareholders. We expect shareholders to continue reaping the rewards of our efforts going forward and not just from debt reduction.

Production and reserves growth certainly have helped drive shareholder value. Importantly, as the organic reserves growth graph shows, not all of the growth was acquired. As John is about to show you, our capital program on our core properties is expected to drive additional organic growth, while further reducing debt through free cash flow.

Now let's dive into the details on the fourth quarter. Starting with the look at the unusual items. On this slide, you can see that approximately $4.5 million hit the financials in debt retirement related to calling the 10% notes and another $4.5 million that related to inducement premiums on preferred conversions. Also, you can see that our insurance costs were $2.1 million higher than our quarter-on-quarter run rate. This was due to a change in the renewal date that caused us to incur an extra month of expense in the fourth quarter.

This next slide highlights a few other line items that could use some discussion. Starting with volumes, we were up quarter-over-quarter and beat our original guidance. Until late in the quarter, we thought the beat was going to be even higher. Then, the hot summer weather kicked in during the second half of June and knocked out a number of compressors. In addition, we experienced downtime as a result of rig moves as we got busy out at South Pass and Grand Isle. Still, we recorded volume growth in the quarter and our capital program added volumes that are lifting current production levels.

Breaking down the different LOE line items, you can see the onetime jump in insurance cost that I discussed. Without the double charge, it would have been about $1.97 per BOE, flat with the March quarter. Going forward, you should expect $8.24 million per quarter or roughly $2 BOE.

The biggest impact on the quarter's LOE was workover maintenance. We had $8 million of pipeline maintenance and another $5 million of compressors, well diagnostic and facility work that was above and beyond the normal items. This work was largely to get our expanded gathering system in condition to flow increased volumes and to prepare to do some recompletes and other activities on wells that will increase volumes going forward.

These maintenance costs should drop back in line moving forward, totaling $10 million to $12 million a quarter rather than $21 million in the June quarter. The September quarter will be toward the upper end of that range since we had some follow-on costs as we wrap up some of the work, which should come in closer to $3 a BOE.

The direct LOE also was higher than it should have been during the June quarter due to operating costs being incurred from government delays in approving the ExxonMobil field transfers. The delay in transferring operatorship cost us about $7 million in the quarter. Those costs should begin coming down now that we have full operatorship, with the last field transferred this week. The bottom line is that even with the unusual expense items in the quarter, we delivered EBITDA of nearly $43 a BOE.

Speaking of revenue, there has been a good deal of press regarding the recent decline in WTI. Energy XXI sells HLS, not WTI. So while WTI has declined, the HLS-WTI spread has increased to about $24 a barrel recently. Even though WTI is currently around $82 a barrel in the spot market, Energy XXI is still realizing over $100 a barrel for its spot crude sales. Plus, we are realizing good value on our hedges with our $100 WTI puts, giving us an additional $15 a barrel currently.

Because we have previously hedged some of the HLS-WTI spread, we expect to realize about a $12 a barrel premium versus WTI in the September quarter, increasing to about $16 a barrel premium versus WTI in the December quarter. Looking at our aggregate hedging program, we have about 59% of the revenue hedged versus fiscal year '12, and about 44% of the revenue hedged versus Strip for fiscal year '13, providing substantial downside protection.

Now we'll turn it back over to John to give an idea of what the future has in store.

John Schiller

Thanks, West. I want to take a few minutes to highlight our recent activity, and then to present the newly approved fiscal 2012 budget. I'll start with a quick update on the non-operated portion, our ultra-deep drilling with Jim Bob and the McMoRan gang.

At Davy Jones, the #1 completion, everything is moving ahead. We still expect to take the rig that we're currently using, a Rowan EXL 3, and move it over there in middle October and commence with that completion. All delivery items are still running on schedule. We fully expect to have the BOP stack delivered by Cameron at the end of November, which should put us in position during December to conduct a flow test with commercial production occurring shortly thereafter.

At Blackbeard East, we're going in the hole this week to set a whipstock and begin our sidetrack from approximately 30,700 feet. As you know, we have indications on mud log of the Sparta sand around 32.9. I think we'd like to get back down there, see that sand on a log.

At the Lafitte well, we're going to back to drill today. We'll be drilling below 25,600 feet. That well is in the target zone, so it's literally day-by-day. As we drill ahead, we'll see what we see. And then we'll make our logging runs as Jim Bob feels necessary.

Clearly we remain excited about the ultra-deep potential. Meanwhile, we're encouraged by the initial work we've already done on the acquired ExxonMobil properties. I'll focus for couple of minutes on South Pass 89 and Grand Isle 16.

The South Pass 89, we've completed 3 workovers. The first of which we reported mid-January was brought online at 2,500 barrels a day. That was equal to what our total expectations from the entire 6-well program were. Since then, we've completed 2 others as announced last night. Those wells you see detailed on the South Pass 89 slide have also outperformed internal expectations. A-16 and A-17 wells came on at a combined 1,700 barrels of oil net, exceeding our prework estimates of 600.

Grand Isle is delivering similar results. Even before we got the XL 3 rig out there, we were able to do 3 tubing recompletions at very little cost with nice results. The biggest surprise was the J-21, which was expected to be a gas zone, but instead, tested at 1,200 barrels of oil a day. Because it's oil rather than gas, we'll need to do a gravel pack because we have some sand control issues there, and we'll get that zone on production in the later.

Once we get the rig out of there -- once we got the rig out there, we were able to recomplete 2 other wells. The J-30 and the J-32 wells have recently been put on production at 1,100 barrels of oil equivalent a day. We've moved the rig off the J platform and have moved it over to the P platform to do the next 2 recompletions.

The work at Grand Isle and South Pass were initiated ahead of the official start of our fiscal 2012 capital program, and it's certainly given us a head start on the new year. Let's take a look at the official 2012 budget and what we expect from it.

Our board has approved an initial budget of up to $450 million. We expect to spend that but we're working within a range of $380 million and $450 million, with a flexibility to adjust as we go based on results and whatever the market might throw at us. Said another way, we've set aside $70 million into the kitty so that we make sure we move the money where we make the most for it as we see the results on some of the Exxon projects, and we're ready to deal with the volatility that we've seen in the market in the past several days.

For the purposes of this presentation, however, we will think in terms -- we're going to talk in terms of the $450 million budget shown on the slide. I'll highlight a couple of key points. First, $316 million of the $450 million budget is dedicated to drilling and completion, with 30% of that for exploration. $214 million is being dedicated to our core business, with the majority going to the newly acquired fields. The remaining $102 million drill and complete spend is going to the ultra-deep partnership with McMoRan.

As we highlighted during our Investor Day presentation, our analysis indicates that we feel very comfortable spending up to the full $600 million of ready-to-drill projects, and could actually generate even more free cash flow for debt reduction if we did that. But our current plans, as we look at our staffing, as we build into the Exxon asset acquisition, is that I see that occurring somewhere in the 12- to 18-month range before we started hitting that $600 million level.

We're going to be slow and methodical about it. We're going to make sure that the fields we put our money to work in are the correct ones, so that everything we do is a present day dollar derived per dollar invested, and we want to make sure we generate the max value for our dollars. Given the bulk of the incremental unfunded projects came to us through the Exxon acquisition, we got a team that make a slow start there.

Based on the preliminary results at South Pass 89 and Grand Isle that I discussed a few minutes ago, we're certainly encouraged that the opportunity set is real and understated, if anything. As we log more results for the program, we'll continue to allocate our flexible capital to the most profitable opportunities.

Taking a big picture view of the capital program, this slide is updated from the one we first showed on our Investor Day back in May. The 2012 list represents a wide range of development drilling as well as exploration prospects on our core properties, excluding the ultra-deep. There are number of low risk PUDs on the list and target quick payback volumes. In addition, there is multiple exploration projects that target substantial reserve adds.

As I've said, the list will remain fluid and early success of the drilling program could pull some of the other prospects forward. The key here is that we have a multiyear inventory of ready-to-drill projects and more than 85 additional projects that will be maturing and moving forward, all of which are located on properties that we hold by production with no gun to our head to get out there and drill. Success in the list of projects would certainly add to that list as we apply what we learned to other parts of the portfolio.

Looking ahead to fiscal year 2012, as we discussed in the release, we shut in a large amount of production during July to replace a key pipeline and for rig movement as we got started with the capital program. Since then, we've made good progress, so we expect the volumes for the current quarter to be flat. This represents about a 4% quarter-to-quarter growth when you subtract out the South Louisiana divestiture.

Current production is running well in excess of 43,000 barrels a day and our capacity is in excess of 46,000 barrels a day. We're adding volumes daily with our ongoing work in the field. For our full fiscal year 2012, production should range between 46,000 and 50,000 barrels a day. This is unchanged from our previous expectations, even with the downtime we've seen and have baked in to the numbers.

In terms of both volumes and operating costs, we have high expectations for acquired -- for the acquired Exxon properties, now that we have operatorship control of all the fields. As of this week, we're no longer paying Exxon a management fee on top of their expenses, and we're no longer paying 2 separate crews to operate the same facilities.

We set the table this quarter with some major expenses on the Exxon properties in order to reap the rewards going forward. That, combined with the attention our crews bring to the platform, should start paying dividends this quarter, with the December quarter seeing the first clean results of a true Energy XXI operation. Higher volumes and lower cost should drive record EBITDA for fiscal 2012 allowing us to continue to reduce our debt and build our cash position.

And if volume growth and free cash flow aren't enough of a catalyst for you, there's always the ultra-deep shelf to look forward to. Besides drilling at Blackbeard and Lafitte, and anywhere else we may go this year, the clear catalyst will be the first production of Davy Jones.

And summary, I believe we're headed into an exciting year with multiple catalysts both in our core properties as well as our ultra-deep drilling program, looking forward on our oil Strip, we still expect to roll out in excess $100 a barrel. And Energy XXI has never been stronger and better deliver -- positioned to deliver shareholder value.

And with that, I think we'll open it up for questions, operator.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Jeff Hayden from Rodman & Renshaw.

Jeffrey Hayden - Rodman & Renshaw, LLC

John, first of all, just got a question for you on the 2012 guidance. How should we think about that range and kind of the impact of the various spending levels? Is it kind of the 50 would be $450 million in CapEx, whereas the 46 would be $380 million. How should we kind of frame that?

John Schiller

I think that's the right area, Jeff. The low end, obviously, we may not get 50, we're going to be closer to 46. I will also say that part of that range, though, is associated with some of the type wells we're going to drill this year. We're putting a bid towards some wells that can give us 40 million, 45 million a day of gas. So those are some -- those are 100% wells, so those are some big volumes. So now the right sequence occurs, we can spend the low end of CapEx and still hit the high end on the production side. But in general, what you stated is the right way. We -- the low end is representing more of a less CapEx case; the high end, the upper CapEx case.

Jeffrey Hayden - Rodman & Renshaw, LLC

Okay, great. And then, just for your kind of that fiscal Q1 expectation of roughly flat, what sort of a timing expectation is built into that as far as one that 2,600 barrels a day shut-in volumes comes back online?

John Schiller

Yes, West kind of alluded to it a little bit in his talk, but the simple reality is it's freaking hot in Texas, guys, in case you haven't figured that out, and it doesn't get any cooler offshore. So our guys are working really hard. But a lot of this Exxon equipment, we have some of the original compressors ever built by companies, stuff that's been out there 50 years. When it goes down, we sometimes have the machine parts, there's not a parts catalog you go to and order the parts. But they work, but the heat's getting to them. We shoot for 97% operating efficiencies. And so what I'm telling you is that down volume is not necessarily one project I'm telling you we got to go finish and get back on, although right now there is one compressor down. But it kind of pops up here and there. So we have days, during the month of July, we have some 47,000, 48,000 barrels -- I mean month of June, we have some 47,000-, 48,000-barrel-a-day days pre the divestiture. We also had some 38,000 barrel days when things were going the other way. So you're going to see some variation in there, but we feel very good with the guidance we're giving you. Our course, I guess, we got to talk about hurricanes, but the flipside of Texas being so hot is it's hard to bring that weather down here this year. So we'll continue moving forward and we'll clean out. A lot of this money we spent this quarter when I talk about setting the table was taking things -- taking care of some things that probably needed to be taken care of 2 or 3 years ago, but because of the nature of the animal and the materiality impact, a company the size of Exxon wasn't necessarily capturing capital to fix. So this is the same thing we've done on every acquisition we've done. We get out there. We get the facilities and the compressors and the pipelines up to the -- what our expectations are of the company, for Energy XXI in particular, and then we go about making a lot of money off of it.

Operator

Our next question comes from the line of Duane Grubert from Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP

Yes, John, I am interested in this notion of you increasing your capacity to do work. So, you say, we've got a bunch of projects, but we're going to work our way into that. Can you describe to us a little bit about how does that capacity execute increase, whether that's learning curve stuff or more people, or how do you see improving and growing your capacity?

John Schiller

Duane, great question. There's a couple of different elements to that. The first part is staffing. Tom and his guys have been adding to the staff, bringing on people that we're very familiar with, great group of technical guys that continue to come on board with us. Some of it is getting them up to speed and how we do things. Some of it is just getting them into shops so that we're ready to increase our activity level. A big portion, relative to this year's budget though, is simply some teams are ahead of other teams. And we went through our detailed budget process, some of them were willing to start telling us how they felt the volumes were going to come in, and others were still in a position where they were just telling us what Exxon said about the volumes. And so we're like taking advantage of mine and Ben, and 30-plus years of experience in the business, we felt the best way to go about it was those teams that didn't want to promise very much weren't going to get a whole lot of capital right now. But when they brought on their wells, and they were actually 1000-barrel-a-day wells instead of 300-barrel-a-day wells, we might want to spend the more money there. And so a large portion of that is just let's see how the fields come in, the different areas, and then I want to make sure we put our money to the best projects. Because I will tell you that if you run out there and just start spending $600 million -- we can spend it, but we might end up with a P/I that's a quarter less than where we wanted to be had we done a better job of choosing the specific projects.

Duane Grubert - Susquehanna Financial Group, LLLP

Okay, that's a great answer. A second theme, on the Netherland Sewell estimate that they gave you, I assume there was probably some give and take between the operator and maybe you guys with Netherland Sewell. Is there anything you learned about what kind of data these guys want as you go forward on the exploration program, stuff you might do differently in the future to get an estimate that might more closely match what McMoRan had been putting forth, for example?

John Schiller

Yes, I think clearly -- and Jim Bob and I have had this conversation. We are going where no one's gone before. And so you're down in an area where the geology is totally different than everything else in the Gulf of Mexico. Yet, in general -- I'll see if Tom agrees with me, but in general, the guys who are doing the reserves are still trying to apply regular Gulf of Mexico geology to the structures and all. And so they take a fault that we think is inconsequential because it's compression fault and it doesn't really seal you off from the reservoir, and they want to treat it as a isolating fault, like it would be anywhere else in the Gulf of Mexico. And so we're continuing to push to look for analogies around the world to show them, to kind of force them to look at some things a little bit different. And I think we will get there. Obviously, the big production test in Davy Jones is the first step. In general, as we noted, as long as we have true third-party reserves, reserve engineers doing their work, they're probably going to continuously see positive revisions. I mean they drive the number to where they're 90% certain it's there. And they're 90% certain, probably 110% certain at the end of the day. So but we're working with them. I think there is some things that we know we need to capture data a little bit different than we are, and we're working on that. One thing I will tell you, the overall picture, even since they did our reserves this year, we continue to get more and more data as we're analyzing everything out of Davy Jones. And as I've said many times, there's nothing but more and more encouragement that everything we tell you is there is there.

Duane Grubert - Susquehanna Financial Group, LLLP

And along those lines, on Lafitte, you guys have given where we're drilling and operations continuing and so forth. Is there anything that you can give us incremental in your impressions of the zone that you're drilling through in Lafitte?

John Schiller

Well, that's the impression. Last time we went in, we're drilling quicker than the last bit trip, so there was a good change of bit there. We had mud log things, Duane, and I just -- as Jim Bob, we're very hesitant to talk about mud logs. I think we'll continue to drill with this bit. And as we dull this bit, might possibly make a log run. It just -- it depends on how things are going and what kind of penetration rates we're making and things like that. But we're clearly in an interval where we want to be. We're in an interval that should have sands. The Paleo setting is correct. So it's just a matter of drilling the well out and getting the log.

Duane Grubert - Susquehanna Financial Group, LLLP

Okay. And then on a totally different topic, in terms of hurricanes, and I'll do you're tapping as well, can you talk to us about how your diversification of production facilities have improved your risk to hurricanes? In the old days, you had a lot of production in individual facilities, and I think that's a lot better and that would be worth talking about a little bit.

John Schiller

Yes, it's a good point, Duane. With the Exxon acquisition, while we're still focused offshore Louisiana, when you go through and isolate the impact of hurricanes, it's there's a lot of -- because of the last few big ones, we've gained a lot of knowledge in our industry, and basically, you need to be within 18 miles of the Northeast of the eye, where the big wall and the big...

Duane Grubert - Susquehanna Financial Group, LLLP

Winds?

John Schiller

I guess, it's the water, but...

Duane Grubert - Susquehanna Financial Group, LLLP

Waves?

Unknown Executive

The storm surge.

John Schiller

The storm, they have -- the storm surge is coming. That's where you see the most damage to your structures. And so when you go through and look -- and we did this for the London insurance market, when you go through and look at how we're diversified now, the numbers of structures, where they're located, you just can't really build any sort of perfect storm that does a ridiculous amount of damage to your facilities. You're probably in a position now where it's hard for us to take out more than 10% to 20% on the upside of your production with any one storm. And so, we've looked a lot at that. We know how things go. We're very well insured. And we go through another summer and we'll see what happens.

Operator

Our next question comes from the line of Ron Mills from Johnson Rice.

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

Questions on some of the South Pass and Grand Isle work in the tables that you provided. The work so far has exceeded your expectations. I just want to clarify the expectations that you had before you did the work. Were those old Exxon expectations and the wells came in better, or were they yours? I'm trying to get a sense as to -- go through -- as we go through the completion process, if Exxon had expectations that conservative, if it's something that's going to be likely to continue?

John Schiller

Yes, I mean, Ron, that's a great question. And I truly to tell you, this is going to be the last quarter we talk about expectation differences like this, okay? But yes, all of this stuff we're talking about were part of that, particularly South Pass, was driven by what Exxon already had in place. We already had the rig and the wells identified. And so there's a lot of reasons. They may have been quoting average for 2-year numbers. I don't know what they were doing. But yes, their expectations were different than ours. Every company kind of has its way of doing things. Ours has been from day one, pretty brutally honest with you guys. We don't try and sandbag you, and sometimes we're going to disappoint you, most of the time we're not, hopefully. But we tell you what we think they're going to make. And as we move forward from here, I think that's what you'll see. When we talk about expectations, they will be Energy XXI expectations. They'll be more in line with things like Ashton and Onyx, where one was a little higher, one a little lower, bottom line, the 2 wells together came right in where we expected them to be.

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

Okay. And as we look through the timing of your recompletions and new drill activity this year to get to that, given the starting point in the first quarter and get to the 46 to 50 average. Is the activity pretty evenly spread, and the expected production growth over the remainder of the year pretty evenly spread? I guess that's one part. And the second part is how much of Davy Jones do you have in your fiscal second half numbers included to get to that 46 to 50 range?

John Schiller

Yes. The first one, yes, it's pretty evenly spread. I mean we're going to be doing -- continue to do work out of Grand Isle. We go from a recompletion to a drilling program there. You're going to see us do stuff out of the South Timbalier, west up to 73, we'll keep a rig running. So it's going to be that type of stuff. Later in the year, now that we have South Tim, second half of the year, we'll move over to South Tim 54 and start doing some work there too. So you got 3 big Exxon fields, Grand Isle, West Delta and South Tim, that are getting the majority of the work. A few of our core legacy assets will be getting work done on them too, Main Pass and South Tim. With regards to your second question, so what's the number?

David Griffin

Yes, but he's asking what the piece of Davy Jones is...

John Schiller

1,000 barrels per day, cooked in for the Davy Jones.

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

So, for the second half of the year?

John Schiller

Starting in the second half -- starting in January.

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

Okay. And then, and just on the cost side. But so going forward, I just want to make sure I heard that right, you have probably $10 million to $12 million worth of nonrecurring cost that have hit you in the last quarter that won't hit you this year, and then room for further improvement once you get rid of the redundant Exxon management fee costs. Is that the right way to look at the LOE on a BOE basis?

David Griffin

That's right. I mean on -- as I mentioned before, on the maintenance and expense workover, we're looking at $10 million to $12 million sort of range in the quarter for about -- in September it will be about $3 of BOE. And then the direct LOE, that should come down by about $7 million versus this quarter.

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

Okay. And then lastly then on for the U.S. On the G&A side, given the fact that you all have been hiring a lot of people. It sounds like you're pretty well set. Is that fourth quarter run rate of $17 million, $18 million, is that a better run rate for your G&A given the incremental staffing?

David Griffin

Yes, that is pretty much right in line with kind of what our expectations are going forward.

John Schiller

Ron, let me follow up with one thing, if I can, on the operating expense side. Exxon is a machine, and you guys have all heard me tell you, my dad was 37 years, I think the world of what they do, but they're a machine. And so not only were these properties not capturing capital, they didn't really trigger a materiality impact on the company either. So we've literally, for the last 7 months, get a monthly bill from their operator for operating expenses and everything else. It's basically that. It's an invoice. Delving down into their system for the same kind of detail that we track on all of our fields, which is one of the things that allows us to do -- the optimization on costs that we do just doesn't exist. And that's a little bit of what's been going on in this quarter. We're just getting some big numbers. It takes a long time to get through and figure out what they really are charging us for. So I think you'll see a lot of improvement now that they're totally out of the picture, and we control our invoices and we know what we're spending. And it's going to be nothing but upside from here on, on the LOE side.

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

And is most of that work now behind you? I know the pipeline reroute was the big item in July, that are you now at a point in terms of the big maintenance and pipeline work to be able to go forward relatively unencumbered from a production standpoint, x some of the compressor work?

John Schiller

Yes, I mean you're going to have a compressor go down from time at a time. The big Exxon pipeline projects we identified are done. The big Exxon cleanup projects that we needed to do are done. One of our major pipeline expenses was not an Exxon pipeline. The Eugene Island 275, that had filled up with paraffin. So we've taken care of that. We'll be getting that production on soon. Going forward, there's going to be some couple of million dollar deals here and there to finish doing some work around the base, but it's not stuff we have to run out and do. We'll do it when the time is right. While we're talking about costs, I will tell you one more thing. It continues to amaze us. We've got a P&A package out of South Tim 21, and literally, probably in the 6 years we've been in business, Nelson never seen people fall over themselves like they are to bid on this thing.

Nelson Steve

That's correct.

John Schiller

I mean, there is just -- the impact of the deepwater in the Gulf are starting to come all the way down to barges, where guys with big barges are willing to do what for them is tinker-toy work at South Tim 21 area. And so it's really -- we're taking advantage of that. You'll see us continue to get structures out of water as we abandon wells and all, so that we take advantage of where the call structure is right now in P&A work.

Operator

Our next question comes from the line of Richard Tullis from Capital One Southcoast.

Richard Tullis - Capital One Southcoast, Inc.

John, just trying to get a feel for the Oil & Gas percentage going forward. The current production, how is that split? Is it similar to what you saw in the past quarter?

John Schiller

Yes, we're roughly 2/3, 1/3 for a while still. We got to bring on several more material gas wells before you make any sort of significant change on that. But in every forecast we look at going forward, Richard, we stay above 50% oil. I mean that's out 3 years looking, I'm talking about.

Richard Tullis - Capital One Southcoast, Inc.

Even including the ultra-deep production of...

John Schiller

Yes, sir.

Richard Tullis - Capital One Southcoast, Inc.

Okay. The 46,000 to 50,000 a day of guidance for fiscal year '12, how much daily downtime is built into that forecast?

John Schiller

Well, we do -- like for this quarter, we built in prebudget for the budget about 10% -- about -- it may a little bit less than 10% downtime for the hurricanes. So every month we go without a hurricane helps us gain against our budget numbers. Overall, it's a little bit different process. You kind of build -- what you're really doing is building in downtime that's consistent with what you've had in the past. And so it's not like we take our top rates from our wells and forecast from there. We forecast off wells that have suffered downtime every month. So it's kind of -- it's implied within the number we give you that we have downtime. What does it run? Somewhere between 3% to 5%.

Richard Tullis - Capital One Southcoast, Inc.

Okay. The list of the wells to be targeted in 2012, where you're sitting now, what are the ones that you would focus on, say, in the first 3 to 6 months?

John Schiller

Yes. It's -- we're going to give you some sense here. We're going to go out to West Delta starting in September here. We're going to drill mostly PUDs there. We'll got a couple of step-out wells. Is Rosebank on that list?

David Griffin

Yes.

John Schiller

Yes. Rosebank and Whaler are a couple of ones we're going to do there, Weimer. And then as we go over to South Tim, Sparkplug, the number one on the list, we'll get that well drilled along with Carberator. And then Wombat will be next spring, when we get ready for it. Magnum's on there. Abbott, Costello. We're probably drilling about -- all of these are getting drilled?

Unknown Executive

2/3.

John Schiller

All of them. Pretty much everything you see in 2012, we'll get drilled or started on this year.

Richard Tullis - Capital One Southcoast, Inc.

Okay. And then just finally for me. Any more properties looking to divest?

John Schiller

Not really, Richard. We pretty much like the asset fixed the way we have it. And we operate a huge percentage of it. So we don't really see that occurring.

Richard Tullis - Capital One Southcoast, Inc.

Okay. And then on the acquisition side, seeing anything -- what's the outlook there and what do you see in it as far as potential deals?

John Schiller

I mean we look at a lot of deals. Obviously, any banker earning his keep is going to bring us every deal on the table to get looked at. So we'd see a lot of deals. But I will tell you that at the end of the day, you look at the organic growth we're telling you about, you look out over the next 6 months and the material impact on things from Davy Jones and the ultra-deep, it's just hard to make yourself want to go do much, particularly with the stock price where it is right now in terms of doing any other big deals. So I think the foreseeable future, we focus on the assets we have and continue to show you guys how great those assets are.

Operator

[Operator Instructions] Our next question comes from the line of Nick Pope from Dahlman Rose.

Nicholas Pope - Dahlman Rose & Company, LLC

Just looking at kind of you all's Analyst Day, it seemed like South Tim 54 had some -- I guess the kind of suite of wells there, had some of the most kind of production, near-term production potential. And so now that you've got that under operatorship, I mean do you see that field being able to produce kind of that uptick similar to how South Pass 89 did? Or is it more trying to keep things flat at that field at this point?

John Schiller

No, no, no. We clearly -- what you saw was you picked up the right information, we clearly had that as a growth field. We've got a rig scheduled to get there in October. And we'll drill a B30 up-dip PUD, and then Sparkplug, then Carberator, and then Wombat. So we're going to knock out a large piece of what you saw in the Investor Day right off the bat.

Nicholas Pope - Dahlman Rose & Company, LLC

And the South Pass 89, the rates that you all have gotten it up to, is that something you all think you all can maintain at those higher rates, or is this something just coming from flush production, from some opportunities whenever you all took it over?

John Schiller

Yes, I wouldn't necessarily say it's flush production, a lot of that's new work. But it's going to be what you expect. You're going to -- we're going to produce the well. We're going to be making $17 million today, at $17 million a day for about 80% of the reserves, and then it's going to go on decline. And then, you probably get a deal with 6 months to a year before it goes off. And then we'll slide a sleeve and move to the next zone. So you'll see some ups and downs, but you're not going to see 5,000 barrels a day be 3,000 barrels a day next quarter.

Nicholas Pope - Dahlman Rose & Company, LLC

Okay. That's helpful. And then, just kind of on a little different topic. The -- do you happen to have a breakout in terms of that PV-10 value you gave, of how much is coming from kind of the proved developed side versus the PUD side? Like put it on a percentage basis?

David Griffin

It's in the table.

Nicholas Pope - Dahlman Rose & Company, LLC

On the -- the PV-10?

John Schiller

Hold on, we're looking it. So you're asking on the proved reserve? Or are you asking -- what are you asking, Nick?

Nicholas Pope - Dahlman Rose & Company, LLC

On just the PV-10 value they gave, the $3.6 billion?

John Schiller

$3.4 billion. 56% of that is PDP, 18% is PDM, behind pipe, and 26% of the value is PUD.

Nicholas Pope - Dahlman Rose & Company, LLC

That's of the PV-10, though, right?

John Schiller

That's all for PV-10. Yes, that's each percentage of the value.

Operator

Our next question comes from the line of Biju Perincheril from Jefferies.

Biju Perincheril - Jefferies & Company, Inc.

John, can you talk about that 2012 drilling program, the reserve upside that you were -- the reserve exposure there?

John Schiller

Yes, I mean I would tell you, Biju, that some of it is going to be PUD drilling and, obviously, we're redeveloping reserves. And some of it's going to be adding some pretty good reserve adds. Yes, I mean, we've got the kind of wells, Biju, that you take a Golden Bear, you take a Wombat, any one of those wells is capable of putting reserves on the book that replace half your production for the year. So we use -- on a risk basis, we kind of -- we expect to replace production. Any of those wells come in, or ultra-deep starts coming in, like we think it will, then the number gets even better.

Biju Perincheril - Jefferies & Company, Inc.

Right. So if I look at this list, so everything except 4 -- I think it's 4 or 5 wells that are potentially adding new reserves non-PUD?

John Schiller

Yes, I mean -- 4 or 5 PUD wells, you said? The rest are not?

Biju Perincheril - Jefferies & Company, Inc.

Yes, is that correct?

John Schiller

No. I mean we've got 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12 -- we've got about 15 wells that are development wells from our viewpoint. All of the development wells, guys, on here are proved? Are proved. And we've only got 1, 2, 3, 4 exploration wells plus the ultra-deep. Not all is proved on the books. So it's probably 60% development, Biju, and 40% that aren't on the books right now.

Biju Perincheril - Jefferies & Company, Inc.

Got it. Okay. And then, I would imagine you will have a pretty extensive workover program going -- or recompletion activities going on, on the acquired properties. How should we think about reserve adds from those?

John Schiller

Well, I mean -- well, I'll tell you in general, like if you go and look at Exxon -- I'm brain dead. What did we end up booking for Exxon, 54 million barrels? We ended up booking almost 54 million barrels. And when we bought the acquisition, we told you it was 50. So that gives you some sense of where we were. We were doing recompletions to zones that weren't on the books, and they came in very nicely. So in general I would tell you, is I kind of stated when I talked about Netherland Sewell, they get paid to give us a number per the SEC that's 90% probability of never being revised down. And so as we drill the PUDs, as we do more behind pipe work, you're going to see us continue to put reserves on the books. We just did -- I'll give you an instance, and Nelson is going to have to tell me current production rate. But we just did a hole in the tubing on a well that had been shut in since 2007, it went off making 80 barrels a day. We did a simple pack off, took the pressure off the case and it held, and now that well is making...

Nelson Steve

About 485 barrels of oil a day.

John Schiller

485 barrels of oil a day. So that's an incremental 400 barrels a day. Probably none of it was on the books, to be honest. The 80 would have been written off when they lost the well. So I mean those things are happening day-in and day-out. And we try and sort of look at it on an every 6-month basis in terms of what that impact is on our reserves. But all of that is positives. And we have had not one single negative surprise yet at Exxon. Everything is to the upside.

Operator

Our next question comes from the line of Andrew Coleman from Raymond James.

Andrew Coleman

I had a couple of quick ones here. Are you guys still targeting something like a 40% debt to cap here in the next 12 months? And should we think about you beginning to pay down that $1 million a day number, do you think you might increase it from there?

David Griffin

Yes, Andrew, the -- our debt to cap right now, it's a little over 50%. We're going to continue to drive that down just through internal cash flow and debt repayment. Long term, we expect to get down there to the 40% range. We, depending on what happened with commodity prices, we'd have to have a little wind at our back to kind of get there at the end of this fiscal year. But we're going to get there over the next -- certainly, within the next 24 months.

Andrew Coleman

Okay. Great. And then, just looking at your reserve report, you guys had about 30% PUDs. Again, I think you had some comments earlier in the beginning, which I missed part of. But with having all these properties under your belt now and operatorship, and having just the lower cost structure that they provide, I guess how would you think about maybe increasing the PUD level as you go forward over the next couple of years?

John Schiller

Yes, Andrew, we talked about a $450 million budget with $70 million of flexibility. We haven't necessarily designated where that money is going to end up. And so that's based on building into these Exxon assets and which ones continue to deliver even better than we think, which ones are sort of average, if there are any. And then we'll start allocating that capital. And then along those same lines, that we're sitting here a year from now talking, I think you'll see us starting to ramp in towards that $600 million CapEx number. That really starts generating a lot of free cash flow. We just want to make sure that every dollar we spend -- excuse me, particularly in the environment we find ourselves on the markets in the world, that every dollar we spend goes to what we think is the maximum present value gain out of our portfolio.

Operator

Our next question comes from the line of David Magruder from Knighthead Capital.

David Magruder - Knighthead Capital Management

Sorry if I missed it earlier, but you commented on debt reduction as being a part of, let's say, your cash flow. But can you just talk about your ability to buy back stock? And two, if -- how do you think about buying back stock versus debt reduction? Because you have so much free cash flow projected in the near and long term.

David Griffin

Sure, we have -- in terms of buying back stock, we're limited in terms of what we can buy back currently by our current credit arrangements with our corporate revolver. We do have a certain amount of cash at the Bermuda level, which we could utilize to buy back stock that's currently about $28 million. And from time to time in the past, we have repurchased stock, or the stock that is to be issued to employees as part of their restricted stock units and various other compensation programs. But we do it really on an opportunistic basis depending upon our liquidity and the way we look at the current stock price. But we do have some ability, but it's pretty limited right now.

Operator

[Operator Instructions] And our next question comes from the line of James Silcock from James Caird Asset Management.

James Silcock

I just wanted to get a little more color on your hedging strategy. We see here on Slide 13, you've got 59% of projected revenue for this upcoming fiscal year hedge and 44% in 2013. Just given the pullback we've seen here in the commodity curves, how do you guys kind of look at your hedging strategy going forward? And then also with respect to hedging, do you guys target a particular percentage of estimated production or PDP volumes?

John Schiller

Yes, they -- well, actually, a couple of different things. First we're, under our revolver, we're limited in how much we can have, and it is tied to a percentage of PDP. So we can go as much as 85% PDP. But when all you're looking at is that and the decline associated with it, if you get 50% of that booked for 3 years, that's a pretty good hedge position. As we've been talking about, we've had very long strategic discussions at our board meetings for the end of the year. What you'll see us continue to do is protect the downside and leave ourselves a lot of room to the upside, particularly with regards to oil. You've seen that as we've moved swap positions over time from 75% of our hedge to 50%. I will tell you, for instance, right now, in this whole situation we find ourselves in, we went out in calendar 2013 and pulled off about 1 million barrels of swaps we had. We made about $5 a barrel on the position. Those were $94 barrel swaps and we're replacing them with $80.125 Brent collars. And so what it does for us, it gives us a lot more room to the upside. It takes a position that just 3 months ago was a negative $20 million or $30 million mark-to-market against us, and we get paid for the position. So we're doing some things like that, where we continue to get out the swaps and protect ourselves from the downside and give us more room to the upside.

And with that, ladies and gentlemen, thanks for your attention today. And we'll be back next November -- in November, and catch you up with things, if not sooner, with the activity that we got going on. So thanks.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program and you may all disconnect at this time.

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