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Energy XXI (Bermuda) Limited (EXXI)

F1Q10 (Qtr End 09/30/09) Earnings Call Transcript

November 3, 2009 10:00 am ET

Executives

Stewart Lawrence – VP, IR and Communications

John Schiller – Chairman and CEO

West Griffin – CFO

Steve Weyel – President and COO

Analysts

Neal Dingmann – Wunderlich Securities

Duane Grubert – CRT Capital Group

Evan Templeton – Jefferies

Operator

Good day, ladies and gentlemen, and welcome -- I'd like to welcome everyone to the Energy XXI first quarter 2010 earnings conference call. During the presentation, all participants will be in a listen-only mode. A question-and-answer session will follow the company’s formal remarks. (Operator instructions) Today’s conference 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, Danna. Welcome to the call today, everybody. Presenting today, we have John Schiller, Chairman and CEO; Steve Weyel, President and Chief Operating Officer; and West Griffin, Chief Financial Officer, who will be available to answer your questions at the end of the call, of course.

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 night and in our public filings. We disclaim any obligation to update these forward-looking statements. While the company believes these forward-looking statements are reasonable, they are subject to factors such as commodity prices, competition, technology and environmental and regulatory compliance.

Our drilling schedules, capital plans and other factors may cause our results to differ materially. I urge you to read our 10-K and most current 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. A year ago on this call we talked about what difference a year makes. We’ve just been hit by two major hurricanes and a global economic collapse, and things were about to get worse rather than better. It’s not an experience any of us would ever care to repeat. Today we can definitely say what a year of difference makes.

The outlook is very good. Since July 1st, when we started our new fiscal year, we successfully launched our capital program, drilled three excellent wells that have just come on line at a combined rate of 6,500 barrels of oil equivalent a day gross or about 2,600 barrels a day net to us.

We brought on the Fastball project with our operator Newfield, on line at 770 barrels of oil equivalent a day net to us, which is about half of where we expected to be once it is fully ramped up. We also have advanced our Cote de Mer project, and we have our remaining hurricane volumes that all should come on in the near future, bringing another 3,000 barrels a day of additional net production during the next few months.

In addition to operational success, we made good progress on the financial side. We reached a global settlement with our insurers that delivered $53 million of cash to reimburse the hurricane damage, and we launched a bond exchange in private placement that should reduce the face amount of our debt by about $69 million.

In terms of our bonds, we modified slightly in response to the SEC comments, but we now appear to be on track to close the deal on November 12. During the downturn in prices, particularly for natural gas, our risk management program was affected and protecting our cash flow as designed. The hedge protection and the added production give us further comfort that we will generate significant free cash flow this fiscal year, allowing us to continue reducing our debt levels.

Improving balance sheet, in terms of our flexibility to pursue acquisitions, nothing is currently locked in, so we can’t make any promises, but we are looking at multiple opportunities. One key goal in any acquisition would be to further strengthen the balance sheet. After a tough year of hunkering down, we’re back to actively pursuing our original acquire and exploit mission, and of course we are continuing to pursue our ultra-deep shelf exploration drilling.

At David Jones, we just finished making a big trip and are currently finishing up running casing logs that are required by the MMS, and then we’re preparing to go back in the hole to resume drilling at 26,300 towards our proposed TD of 28,000 feet. Our latest Paleo indicates that we are at the top of the Wilcox sand interval, exactly where we want to be and expect to be. We remain very optimistic about the potential results of deep shelf and we look forward to updating you on our drilling efforts moving forward.

Steve will further review the capital program in a few minutes, but first let’s turn over to West to review the financials.

West Griffin

Thanks, John. We included the key financial details in the earnings release. So let’s look at a few of the line items. Energy XXI generated $51.3 million of EBITDA during the fiscal first quarter, which equates to almost $36 per BOE. Operationally, our daily production volumes declined to 15,500 BOE per day. In fact, we missed the budget volumes for the quarter by only 500 barrels a day, all of which was attributable to a failed gravel pack on the Gouda well at South Tim, which has successfully been repaired.

As John discussed, the production profile is shifted upward, providing confidence in our expectation of that averaging nearly 20,000 BOE a day on a full year basis. In fact, all else equal moving forward, the outstanding results at Main Pass increased the chance that we will achieve year-over-year growth in production.

Cash flow in the first quarter benefited from a higher crude oil mix, which reached nearly 65% from less than 59% last year. Our quarterly pre-hedging revenue was cut nearly in half, going from a record high $94.62 per BOE in last year’s first quarter to $47.64 per BOE in the most recent quarter. Yet again, the risk management program proved its value, adding almost $12 per BOE to our realized price.

Our lease operating costs are a little misleading in the first quarter when you look at them on a BOE basis due to the lower volumes. Our total insurance cost did go up, primarily due to a 20% increase during the last renegotiation, a natural response to the prior hurricane season. But the increase is exaggerated on a BOE basis due to the temporary volume drop.

G&A was up in the September quarter, largely due to expense cost related to the note exchange, which requires certain of these costs to be expensed rather than capitalized. Clearly, this is a one-time charge. Suffice it to say, the second quarter metric should look much better across the board.

One additional item. As we mentioned in the earnings release, we reported a counterintuitive deferred tax expense in the quarter even though we otherwise would have had a small net loss. The full answer is how this occurs is complicated, and we can go through it offline after the call if it’s required. In brief terms, any quarter-to-quarter change in our mark-to-market value of our hedge portfolio requires us to change the amount of deferred tax expense or benefit previously reported. It’s all a non-cash distraction.

Now let’s take a look at the quarter-end in pro forma debt positions. As of September 30, our revolver was essentially maxed out near the $240 million limit, and we had $624 million of the 10% notes trading, with $107 million of cash representing our liquidity position. As of the end of the quarter, we had received only $8 million of the $53 million global insurance settlement, the balance of which has since been collected.

Let’s look at it again on a pro forma basis adjusting for the debt exchange and private placements that are scheduled to close November 12 as well as the utilization of the revolver to support certain MMS bonding requirements and receipt of the global insurance settlement. On that basis, we would have $338 million of the new second lien notes due in 2014, leaving $277 million of the original 10% notes due in 2013.

As for the revolver, the maximum will be got from $240 million to $199 million. And the amount drawn or utilized for letters of credit, assuming we applied all cash at the operating subsidiary level to the revolver, will drop from $235 million to $84 million, leaving $115 million of unutilized availability on the revolver plus a further $14 million of cash at the Bermuda level for a total of $129 million of liquidity.

Total net debt would be $669 million, down from $774 million as of June 30, a $105 million reduction in total net debt. Clearly we are making progress. Looking ahead at the remainder of fiscal 2010, we anticipate reducing net debt by at least another $40 million from internally generated cash flow. Taking all together, we have a manageable debt level, we have liquidity that should cover any foreseeable operational needs, and the balance sheet has improved sufficiently to allow us to become proactive on the acquisition front.

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

Steve Weyel

Thanks, West. We will start with a quick review of the capital programs results so far this fiscal year, which have exceeded our expectation. The Gouda workover and Number 75 recompletion at South Tim successfully restored production from those wells.

Main Pass development drilling resulted in higher than anticipated pay in production levels, which will generate reserve additions from what was intended to be a fed drilling and production acceleration. The A-10 and C-9 wells are close to being fully ramped up, while the A-11 is still being brought up to full production. Similarly, the Fastball project is just in place and it appears it will produce at higher than expected levels, but currently is less than halfway ramped up.

Completion of our Cote de Mer facilities project is progressing well and first production should commence in the next few weeks. Beyond these projects, we continue to expect return of hurricane affected volumes in three significant properties over the next few months. It’s been a long time coming, but we see resolution of the third-party pipeline outages that have kept the volumes offline.

What next? Based on our recent outstanding results, we have additional development activity opportunities we are considering, subject to our operational results in the projects’ ability to delivery high cash flow in this fiscal year. Those opportunities are part of a large inventory of wells in our total portfolio that were made viable, $60 oil and $5 natural gas. At those price levels, we currently have 79 identified drilling prospects in our core fields and the potential keeps growing.

These projects can put 35 million to 40 million barrels of reserves on line for about $350 million in capital, representing competitive F&D costs from slowing economics. Using the recent strip pricing instead of $60 and $5 further boosts our inventory drill prospects. It’s important to note this only addresses the projects we have sufficiently matured. We have leads on many more and expect our portfolio of properties continue a tremendous financials.

We are more enthusiastic about our core properties than ever before. The industry’s recent slowdown has given us the opportunity and step back and to the extent of the property assessment and execute with the best development drilling results in the history of the company. Bottom line, we are pursuing a scale-down capital program as well balanced with an early focus delivering strong near-term cash-on-cash returns around a portfolio that continues with significant upside.

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

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

John Schiller

Thanks, Steve. We are very pleased with our progress in the early part of our 2010 fiscal year. The capital program to date has been a success and we will continue to fuel our growth over the next couple of quarters. Our ultra-deep shelf exploration effort is advancing and we are very excited about that potential. We look forward to closing the debt change in private placement to strengthen the balance sheet, and we are confident we are going to continue to reduce our debt. This improved financial outlook puts us in position to pursue some attractive acquisition opportunities. The dominoes appear to be falling in place for us, and we are excited about the company’s future.

Now let’s open up the lines for questions.

Question-and-Answer Session

Operator

Thank you. (Operator instructions) And we’ll take our first question from Neal Dingmann with Wunderlich Securities.

Neal Dingmann – Wunderlich Securities

Good morning, guys. John, just a couple general questions first. Just wondering -- as you see sort of ramping up, obviously, you mentioned about becoming a bit more active now and carry on with the plan, what are you seeing on service cost, rigs that’s just completion of other costs as well that was one of your favorite, continuing to going to be your favorite?

John Schiller

Yes, I mean -- I think we look at where the rig rates are right now. We’re kind of talking late-1990s, early-2000 sort of rates. But we didn’t show you guys, Neal, we’d just give you some numbers. If you look at the Main Pass drilling program with the cost we had there, we came in somewhere around 20% below our AFE even with reduced rig rates in AFEs. If you look at $60 and $5, we expect those wells to pay out in three months. If you look at the strip, we get our money back in two months. So the economics are pretty compelling. And we will continue to look at those opportunities. That’s what Steve was lighting out for you there, as we look at the rig costs, where we can do things, look at the only assets we have. We see our cash flow. We’re generating significant amounts of cash. We’ll look at opportunities like that to go put some more money to work.

Neal Dingmann – Wunderlich Securities

Perfect. And then what’s your thoughts these days, John, on Gulf Coast? I know you have been really active there lately. Are there some things there that you see that you’d go forward and become operator of?

John Schiller

I think your question is on the Gulf Coast. We see a lot of opportunities there. Most are gases. That’s one of the reasons we are not jumping all over. They are mostly exploration. Another reason, right now, we like the exploration mix that we have and what’s going on in the ultra-deep shelf. And more importantly, most of our leads and our prospects there have a lot of years left on their leases. So we are not really in a kind of buying on any of that. You will see us drill a couple of wells, I think, for the years out. We are looking at right now that you heard us talk about in the past where we brought in some partners and things like that, but for the next six months, I’d say most of the focus is on the Gulf.

Neal Dingmann – Wunderlich Securities

Okay. And then lastly, on -- I'm kind of looking at either like South Tim 21 or maybe 49 or then looking at few of the Main Passers like 61 or 74, are there some additional opportunities there to expand beyond what you all have going on now?

John Schiller

Yes, I mean, a large piece of the upside is at South Tim 21. As you remember, it’s a 100% fill. So when we need to cut back capital, that’s where we’d cut back capital. If we have an opportunity to spend some money from some excess cash flow, that’s the place we will probably spend it. 49, we like some of the opportunities, but remember that’s one of the ones that’s currently waiting on a pipeline that Chevron has got to get in. And we’ve kind of had to sit through and watch a lot of right model [ph], but we kept that project moving on now. Hopefully we’re going to get some volumes late this year, early next year.

Neal Dingmann – Wunderlich Securities

That brings to my last question. Are you now in pretty good shape as far as the infrastructure around other operators and such? You know, you mentioned like waiting on the Chevron pipelines. Anything else that’s sort of hurting some current production because of that?

John Schiller

Yes, I’m sorry. If you look at one of the slides, I think, that’s out there, we’ve got East Cameron 334/335, which is behind the Sea Robin line, and they have just had -- I don’t know, guys -- six times they have tried to start back up. And then we will have additional lead, so they have split and ruptured the line. We think they are close to finding and getting it all repaired. At South Pass 49, as we mentioned, Chevron got in a dispute and decided they weren’t going to lay the line. Exxon got in the middle of it. Now they have decided they are going to lay the line. We are an operator, but we don’t operate the pipelines. So we’re just trying to get a pipeline in the ground, so we can all flow our oil. And then the last one is Eugene Island. What is the last one? I don’t know whose system that is. It’s the closest one to come on. It’s only about 200 barrels a day. The two I named are the big parts.

Neal Dingmann – Wunderlich Securities

Okay, perfect. Thanks, guys.

Operator

And we’ll take our next question from Duane Grubert with CRT Capital Group.

Duane Grubert – CRT Capital Group

Yes. You guys specifically mentioned 79 locations, which is terrific. Can you kind of give us a breakdown? Is that all recompletions or re-drills, new wells? What’s in that development inventory?

John Schiller

Yes, it’s -- where is the slide we have? Majority of those are drilling locations we are talking about. A lot of -- those are all drilling. Those don’t count recompletions and all. Primarily what you would expect them to be, South Tim, Main Pass areas, East Cameron, some back up into the Rabbit Island area, that type of stuff.

Duane Grubert – CRT Capital Group

Okay. And that’s really a huge project backlog. So your capital discipline has been constrained with your balance sheet and so forth. Talk to us a little bit about your process. How do you prioritize with a big inventory like that as to what you are actually choosing to do?

John Schiller

We go through our budget plan and then we have a seriatim that we are constantly updating as we dug out leads, develop opportunities, look at potential. For instance, as we went through the budget, the Main Pass, these three wells really jumped up their cost of their oil and where the stripping moved. We felt very confident in moving those wells into the drill category even though earlier on they weren’t necessarily top wells. So we are all maintaining world ranking on typically as return on our investment or P/I, a discounted present value to the discount investment ratio. And to be honest, Duane, as you know, most of what we do, we expect to make 100% rate of return from the type of wells we drill when you’re talking about two or three-month payout.

Duane Grubert – CRT Capital Group

That’s great. Now --

John Schiller

You try not to stub your toe too often.

Duane Grubert – CRT Capital Group

Yes. And then you used, I think, a carefully chosen word in your release talking about you’re capable of doing 20,000 barrels a day. What takeaway do you want listeners to take in terms of directional guidance for rate on Q3 and Q4 rather than what you’re capable of?

John Schiller

I think the two things on volume takeaway, you know, we missed our internal estimate by 500 barrels a day, all directly attributable to the Gouda well. We side checked that well. We thought we did a good gravel pack. We did a conventional gravel pack, and then all of a sudden we had huge pressure drops. And we made decisions as to pull it. I mean, we could even move 500 barrels of fluid. We’ve reworked it over. We brought that well online. It’s making 1,000 barrels of oil a day. We can move 2,000, 3,000 a barrels of fluid a day with those pack. So the takeaway on that is that we are right where we thought we’d be. We knew we’re going to have a low quarter. If you guys listened in last quarter, we told you that volume was going to fall. We had a lag. But we got all this capital that would drive facilities.

We got Cote de Mer still coming on. So when you look at things, we feel very good. The only reason it says capable of doing (inaudible) is we thought that Fastball would be up and running. And I will tell you now, at Fastball, one of the pleasant surprises there is we thought that year was going to be 75 barrels a million. It looks like it’s going to at least be a 100 if not a 110 barrels a million. So when you are talking about 40 million cubic feet of gas, that’s a significant increase in amount of oil and condensate coming off that well. But Total has been having to, let’s say, fine tune their facilities. So we get 25 million a day once, and we have to shut in. Right now we are around 21, today going to 28. So a lot of that remaining capacity get to 20 is strictly tied to Fastball is not being where it’s supposed to be yet.

Duane Grubert – CRT Capital Group

Okay. And then something I think a lot of people are curious about. You mentioned the casing logs that you are running that the MMS is having you do, can you give us an idea of timing? I recognize you’re not the operator Davy Jones, but the timing of completing casing logging, if u have a successful result there, when do you get back to where we might see conventional logging across its own adventures?

John Schiller

Good points, Duane. A couple of things people forget about in the Gulf of Mexico, especially some of our friends that worry about -- they are also in the West Coast. But here are a couple of requirements that go on from them and ask every two weeks we are required to test our BOP [ph]. Actually it’s every one week, but you can get an exemption for one week. You got two weeks at the most without testing BOPs. The second part that you really don’t get to talk very much about because most wells that we drill don’t get exposed to this, but you only have 30 days to drill inside casing before we got to run inspection log. And what the government is trying to make sure there is that you are not aware now of part of your casings so that you’ve lost either your burst or your collapse ratings.

In case you take a blowout down the hole, you want to be able to make sure you got casing integrity all the way to the surface. So in this well where we have been drilling out of this line for over 30 days when our bid gave out, it was time to change out, we have been 30 days drilling, so we needed to run a casing log. And that’s what we’ve been preparing to do, and it’s finding some mud conditions and things like that. But we got everything in good shape. We are finishing up those logs today, picking up a bit.

What we are going to do is very similar to what we did at Blackbeard that McMoRan was successfully aware that also I think they have used at Blueberry Hill is pick up Weatheford’s mad dash LWD tool and go and hold and see if we can see a bottom 600, 700 feet or so of what we have drilled so far, which we haven’t been able to see except by mud log, and then we will keep drilling. Odds are the tools are going to burn up before we drill with it, but we think about it, at least to try to get some data about what we have right now, then we will continue drilling to our TD.

Duane Grubert – CRT Capital Group

That’s great. Thank you very much.

John Schiller

Thank you.

Operator

(Operator instructions) We’ll take our next question from Evan Templeton from Jefferies

Evan Templeton – Jefferies

Hi, guys. Just a follow-up I guess to the production question. Where are you guys currently running today?

John Schiller

Today, as we speak, we made 19,000 barrels last night, overnight.

Evan Templeton – Jefferies

Great. That’s fantastic. And then also just kind of looking in the slide presentation in your comments, you mentioned Main Pass 61, the A-11 well, as well as the Fastball are only kind of partially up to speed. Can you just break that down and give us an indication where you think the two wells might actually flush out?

John Schiller

Steve, do you want --

Steve Weyel

Yes, this is Steve. I mean, we continue to ramp up A11. A-10 and the C-9 are pretty much where we expect and the A-10 is about 10-13 net to us and to C-9 10-26. We are currently slowing the A-11 at 550 barrels a day net to us and we still have a lot of running going there, but we won’t know until we have it on test for a while exactly where we will be with it.

Evan Templeton – Jefferies

Okay. Similar situation with Fastball then?

John Schiller

Fastball is kind of what I hinted at. We expect to get about 40 million a day out of it; and we are at half that rate right now, 20 million. And it's just really fine-tuning facilities. We have a little bit of problems at the Subsea Tree that causes to take the shut-in in terms of -- and also in terms of pump-ins of methanol. And now we are kind of -- as we are ramping back up, we are working with the facilities that Total has on Fargo and making sure we don’t have too many trips there. And things are going pretty good. I think they intend to get to 28 today, and probably walk it on up from there over the next few days.

Evan Templeton – Jefferies

Okay. Great, guys. Thank you.

Operator

(Operator instructions) And gentlemen, it appears we have no further questions in the queue. I’ll turn the conference back over to you for any additional or closing remarks.

John Schiller

We appreciate everyone joining us today very much. As usual, if you got any follow-ups, get in touch with me or West or Steve or Stewart. We will chase down any answers for you. And we look forward to talking soon on some better results and some good results from Davy Jones. See you.

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