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

Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

Q2 2012 Earnings Call

February 02, 2012 10:00 am ET

Executives

Stewart Lawrence - Vice President of Investor Relations and Communications

John Daniel Schiller - Chairman and Chief Executive Officer

David West Griffin - Chief Financial Officer

Analysts

Joseph Bachmann - Howard Weil Incorporated, Research Division

Duane Grubert - Susquehanna Financial Group, LLLP, 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

Joan E. Lappin - Gramercy Capital Management Corp.

Michael Kelly - Global Hunter Securities, LLC, Research Division

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

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

Eric B. Anderson - Hartford Financial Management, Inc.

Unknown Analyst

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Energy XXI Second Quarter Fiscal Year 2012 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to introduce our host for today, Mr. Stewart Lawrence, Vice President of Investor Relations. Sir, please go ahead.

Stewart Lawrence

Thank you, Karen. Welcome to the call today, everybody. Presenting this today is John Schiller, Founder, Chairman and CEO; and West Griffin, Chief Financial Officer. We'll be available to answer your questions at the end of the call.

Before we get started, I need to remind everyone that our remarks today, including answers to your questions, include statements that we believe to be forward-looking statements. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated.

Those risks can include, among others, matters that we've described in our earnings releases 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 the latest 10-Q to be -- to become better familiar with these risks and our company.

With that, I'll go ahead and turn it over to John.

John Daniel Schiller

Thanks, Dirk. Welcome, everyone. Our second quarter financials were released yesterday. As you can see, we had record earnings for the fourth straight quarter. Highlighted in the release were production volumes of 42,700 barrels of oil equivalent a day, in line with our internal target and up 45% from prior year's average. It's important to note that crude oil production exceeded our budget by about 3,000 barrels of oil a day as we redirected some of our capital oil and away from gas projects.

We also experienced excellent development results on our oil projects. As a result, our EBITDA exceeded expectations with net income reaching nearly $100 million. Since acquiring the Exxon assets in December of 2010, we've increased production from this field by over 20%. A majority of that growth was on the oil side.

Before I update operations and discuss where that growth is coming from, let's turn the call over to West to discuss our financial performance.

David West Griffin

Thanks, John. I want to start by showing a historical chart on EBITDA and net income. As you can see on Slide 6, we more than doubled our EBITDA from the same period last year, with 4 consecutive record quarters. Net income followed suit, jumping almost 9x from the same quarter last year.

Excellent results from our development program drove these results, allowing us to pay down debt at an amazing pace. Net debt has gone from $1.27 billion on December 31, 2010, to $950 million on December 31, 2011. And our net-debt-to-total-cap has gone from 58% to 44% over that same period.

Looking at the capital structure another way, you can see our revolver has paid off, and we currently have about $100 million of cash in the bank. The only real debt remaining are our 2 long-term notes, which are callable until December 2014. So for now, we will continue to reduce net debt by stockpiling cash.

Now let's analyze volumes and revenues for the quarter. We guided last quarter to expect production to rise to around 41,500 barrels a day. As John said, we beat that, coming in at 42,700 barrels a day. More important, oil was 72% of our production, up from 70% a year earlier. The importance of that mix, of course, is a higher margin for oil. The widening spread combined with our higher oil waiting pushed our percentage of pre-hedged revenues coming from oil to 93%. So a 10% or 20% movement either way in gas prices would have minimal impact on our financial performance at this point.

The next slide is our standard per BOE snapshot for the quarter. Everything is moving in the right direction. The maintenance and workover expense is up from last quarter but in line with previous periods, relating to opportunities we continue to identify to add volumes. The production tax/other item is driven by non-cash mark-to-market of derivatives from quarter to quarter, sometimes negative like this quarter and sometimes positive like last quarter. The bottom line is that EBITDA per BOE exceeded the previous record by 15%.

I'd like to now turn the call back to John to update everyone on our operations.

John Daniel Schiller

Thanks, West. In the last quarter -- quarterly call, we reviewed the South Pass 89 recompletion program that have since come to a close. This was the first capital program within the ExxonMobil fields, and it was a homerun for the company. We took gross field production from around 500 barrels equivalent a day to the current level of more than 5,300 BOE.

Grand Isle 16 was our second focus area, and we experienced the same kind of success. We started with 10 re-completions and one development well that boosted gross drill production from about 200 barrels equivalent a day to nearly 5,200. The first development well was Sunny. We targeted the C-2 sand and ended up finding 225 net feet of oil pay in the series of B and C sands. We do competed the well which came on strong and is still producing 1,400 barrels of oil equivalent a day of oil, and we still have the original Permian target C-2 sand gravel pack behind pipe for future production.

In addition, the Sunny well added almost 1 million barrels of oil equivalent with a cost of about $11 a barrel, not a bad start to drilling program on our newly acquired property.

The second development at Grand Isle was Winters, which we are currently completing. This well found 166 feet gross feet of gas sand, 83 feet of net pay and a K-2 sand. We're currently completing this well and expect it to be on production within the next 3 to 4 weeks at rates in excess of 20 million cubic feet a day. Following Winters, we will drill Costello which is another oil well.

At West Delta 73, we drilled the targeted sands at Magnum, the first of a 5-well drill program. The well is with 360 feet of oil pay in 3 Pliocene sands. We expect to have production online at March to add about 1,000 barrel of oil equivalent in a day from that well, and then we have 3 more development wells and one exploration well to drill this year at West Delta 73.

At South Timbalier 54, we're drilling a development well named Camshaft, that well is currently at 4,540 feet. We just set [indiscernible] and we're on our way to a TD at 12,000 feet, which should be another good oil well coming in, in March. That will be followed by another development well called Spark Plug and then Wombat, a gas exploration well.

At Bullfrog, it's been a heck of a well, probably one of the toughest wells I drilled in my life, long displacement. We've set a whipstock and we're sidetracking out back to the amplitude. The well and the offset block is on production. There's a lot of liquids involved in it so we still remain very excited about what we can do with the Bullfrog completion here.

And that takes us to the ultra-deep program with our Blackbeard Magnum. I'll start with Davy Jones, we've displaced our mud with our 18.5 pounds ink drill mud. I think McMoRan did a good job of laying everything out for you. A set bridge plug, one factory, one more factory with our perforating guns, one tubing and install trees, and were about perforating the walling in the flow chart. All should occur this quarter.

At Blackbeard East, we drilled to a total TD of 33,000. We're currently running a liner as we speak, a slotted liner so that we can get production from the Sparta sand. The Sparta carbonate there is a 300-foot thick highly-resistive fracture carbonate based on both 120 for the core data we have along with what we've seen on the logs. I don't need to remind you all, carbonates are some of the largest producing structured reservoirs in the world, so we'll get this line around [indiscernible] and then start looking at just how long it's going to take us to get all completion equipment ready for that well.

At Lafitte, we're currently making a big trip. We've drilled to 33,075 feet. I think it's important there to point out that we -- this well, we're basically because of the technology advances in our business. The annual to do things at 33,000 feet that we routinely do it, 15 to 20, which is we successfully got sidewall course. We got pressures, we got all the logs we wanted across the Cris-R and 3o intervals. And I can tell you from a Cris-R perspective and the data we have, we're very confident that we're going to have a very solid flow rate out of the Cris-R, and that's a discovery, as you heard McMoRan mentioned set up both [indiscernible] and Captain Blood is all set where we can trace that reflector.

Over at Blackbeard West #2, we're now drilling at 15,715 feet as of this morning. We've got a liner drilling at 19,000 feet. From there, we go into the Cupola sand and then another 5,000 for the sand below the Salt Weld. Significance is there, it's that Jim Bob and his guys are doing a great job on this well. We're way ahead of the cost structure and the cost schedule and drilling schedule. We keep that up and I think we'll be starting to show you guys that if we've planned these wells a little different, that we can significantly drive down costs versus some of the other wells.

Our most recent addition to the ultra-deep program is shown on the upper-left corner Slide 22, it's the Lineham Creek well, with Chevron as an operator. Through our partnership with McMoRan, we have a 9% working interest in that well. Chevron considers this their top prospect in the wild card. As you can see, things are picking up across our capital program. Right now, we operate 4 rigs and have working interest in 6 others, which is more than 25% of the total rigs working on the Gulf of Mexico shelf.

We plan to stay home drill a good number of low-risk wells and currently producing reservoirs and continue to deliver record results. That should include a nice bump in volumes this quarter, even larger jump in the June quarter. We continue to feel very confident on our projection of 46 to 50 for the year in terms of thousand barrels equivalent.

I will tell you that the cost of the pipe highway gas wells that we're bringing on, if we hit the low end on the volumes, it will all be because of gas, not because of oil wells are going to miss, and so the resulting impact on EBITDA is nowhere near what I implied low range of the range of production would be.

And with that, I think we'll go ahead and open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Jeb Bachmann of Howard Weil and Associates.

Joseph Bachmann - Howard Weil Incorporated, Research Division

I've had a few questions for you. First on the product mix with increasing to 72% in the second quarter, and as you mentioned, John, bringing on some gas wells in the second half of this fiscal year. Just wondering where do you think that number might drop to back in the high 60s range or kind of where you think it's going to shake out?

John Daniel Schiller

Yes, that's exactly right. For this year, we stay mid-60s and higher in the coming 2 quarters.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay. And is that factoring in Davy Jones as well or that might take another percent or so out of it?

John Daniel Schiller

That's factoring in Davy Jones.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay, great. And then looking at, this may be a question for West on the LOEs, now that all the properties from Exxon under you guys control, just wondering where that number might trend to going forward here?

David West Griffin

Yes. We're still continuing to ring up some operational efficiencies and things of that nature out of those properties. So we're -- you may see a little bit of some benefit there but the real benefit is going to come from our increased volumes. So as we bring on incremental volumes, the LOE isn't going to keep in lockstep, so our LOE per BOE should continue to decline.

John Daniel Schiller

That's right and what you're going to see is we're continuing to do a lot of coiled tubing wells, wireline work, full tubing work, pump jobs, things like that are all in the workload category as we continue to work through the oil well files, look through the wells that were shut in and come up with other opportunity. Plus some of -- Jeff, some of that's reconnaissance also for some of the wells we want to drill helping us predict where the current oil water levels are and things like that.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay. And last one for me on the acquisition front, I think you had mentioned before some of the use of your free cash flow might go towards Gulf Coast acquisitions and/or share buybacks, I'm just wondering kind of where there is -- stand at this point?

John Daniel Schiller

I mean, I think we maintained that we're not really out there looking for acquisitions. We look at everything that's available. But what it takes to hit our sweet spot right now versus the opportunities we have already in our inventory, we're probably going to stick with drilling the inventory. We're going to let the cash flow come to us. In July is when we have our end-of-the-year board meetings. We'll assess what we've done for the year, what our opportunities look like and then we'll decide what all the options are with the cash.

Operator

And our next question comes from the line of Duane Grubert of Susquehanna.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

John, can you give a walk through the timing and the risks associated with the Davy Jones completion at that point? A lot of people are very interested in the step-by-step and in that, you're in a clean wellbore right now, it seems pretty, pretty simple but if you'd walk through it, I think it would be very helpful.

John Daniel Schiller

Yes, Duane. I think people really need to remember, other than the depth that we're working at right now, what we do from here on out is pretty much a standard completion for any high-pressure gas well that we have at our company. So we have a plane-wellbore, we've displaced through it. We're going to put a bridge plug in there. Once we have that set, we'll go in and hang off our perforating guns on a packer, then we're running our tubulars. We got to make a couple of trips on the tubulars and work trains attached to various seal assemblies, but at the end of the day, it's all simple stuff. We run our tubulars very carefully, pressure some very high-dollar tubulars, and we nipple up the tree. Once we nipple up everything and we're hooked up, we'll actually run a firing head into the perforating gun. So during that time, there's no way to fire the guns. Once we run the perforate the firing head in our wireline, we'll pressure up on the tubulars and activate the perforating gun, perforate the well and the well starts flowing towards us.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

And if everything goes really well, what timing do you guys have scheduled for all the steps you just described?

John Daniel Schiller

We're doing it at different depths, Duane, so we're sticking with end of March, we'll know something. It could be a little earlier but let's move on ahead and do some wireline runs and see how it goes from there first.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay, perfect. Now another big activity right now, Dynamic Offshore just got sold to Sandridge at what looks to be a very low price. Did you look at those assets? And is the market missing anything in terms of the buy side value in Gulf of Mexico barrel?

John Daniel Schiller

Well, I'm thinking I'll make 2 very general comments. We're a little familiar with the assets. You remember how those assets came about, 50% oil, 50% gas. There -- they don't have the synergies that we think we have. Their largest oil field would probably our ninth largest oil field in terms of production. So they do have a lot of acreage, that's the upside to it. But we weren't, as we've said, looking for other acquisition opportunities, we knew what was out there. But we have what we have, and the synergies we have around the Mississippi River offshore Louisiana area.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Okay. And finally, can you update us on abandonment liability and abandonment activity for the next year?

John Daniel Schiller

This year, we accelerated some, as you know, because the guys in the Gulf were falling all over themselves to get a little bit of work. So we probably did work us out similar than in the past where it costs us as much as $20 million or 60% of that. Next year, fairly routine. I mean, we don't see any big abandonments out in front of us, things like Grand Isle that were, from an Exxon perspective 5 years away, all this work we've done is continuing to push that further out. The one field we have to worry about is the deepwater [indiscernible] and we still got production there but that -- we're talking less than $10 million sort of events.

Operator

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

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

Just had a quick question here on the road but you guys have mentioned, I guess, at the start of the year, you had a target debt-to-cap, it was getting around 40%. You guys are just about there now. I guess what do you think the next couple of quarters look like if you keep spinning off all this cash?

John Daniel Schiller

Yes, I think there's a distinct chance that by the time we get together with our board in the middle of July, we'll be below the 40% number. We have a good sense of what to do, what our cash flow streams are going to look like, you're going to see us continue to make steps on the hedging viewpoint that protects the downside and gives us the upside. And we're going to have some interesting conversations. I mean, there's a lot of things you can do. I think we want to be in a position that, to be ready go do a deal that comes at us that's in the right areas, and that's a reason to have dry powder. I think we'll look hard at some dividends and things like that and what it does for the stock. But right now, we're just kind of focused on spending smart money, building it up and going from there.

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

Okay. And then kind of building on Duane's question there about the dynamic there, given that you had few quarters to integrate the Exxon properties, have you noticed any change in, I guess, incoming calls in terms of people bringing additional properties to you that might -- going to be looking like taking advantage of your execution kind of capabilities there around those core assets?

John Daniel Schiller

Yes, I mean, we get a lot of deals brought to us, both drilling opportunities in the area and producing assets. We haven't seen anything that we felt the price pay would not have justified versus what we can do with our money, and that's the thing you got to keep in mind. I mean, I think I've mentioned last call that at $75 oil, our inventory of opportunities generates a 1.9 P over I, so we make $1.90 at present value, 10% for every dollar we spend. We can't get those acquisitions in that economics -- I mean, economics and acquisitions. So we're going to charge every use of our dollars against what our other opportunities are in-house. And I could probably say, Andrew, I'll build that case as we build up the cash, and one of the things we're going to do after this call is talk about our strat plan for next 3 years. But as you build up cash, one of the options you have to look at is bringing a little bit more risk into your portfolio and take some of the wells that are out there 4 and 5 years on held by production leases but have big opportunities to them and drill a couple of them over there and just continue to grow and get even bigger. So we're going to look at all those options but right now again, with just all acquisitions we haven't seen that many, and we look at them, I think that would be really good to compete with the inventory base we already have.

Operator

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

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

A couple of questions on -- you touched on it on Lafitte, the well being on time and on budget. Can you talk about the benefits of having 3 or 4 wells drilled in the play now? And how that should continue to benefit you from a, not just a cost standpoint but a time standpoint, in terms of the knowledge gained?

John Daniel Schiller

Yes, I'm sorry, I thought you were making a statement. Yes, we're very happy with what Jim Bob's got going on at the second well Blackbeard West. There's several things to do there. We continue -- McMoRan in general, is a tight company as most independents aren't going to tell you, all the great things they've done from a technology standpoint. But the reality is we're doing some pretty amazing things from the depths we're logging at, the temperatures we're seeing, the length and temperatures where our expendable case has been. And you put all of that together, we're kind of learning a lot of different things. So the key emphasis and one of the things you're seeing deployed at Blackbeard West #3 is that we're drilling smaller hole at the top, we're going to make more use to expandable liners and casings so that we'll still end up with the same size casing for completion but we're not drilling as much rock to get there. And that can have significant impacts on your drill time. So let's see how this well goes. Right now, it looks good. We continue to get there then you'll see us modify how we drill some of these other wells.

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

And can you explain a little bit on the McMoRan predominant press release this week in terms of the 300 feet of fractured carbonate and the implications for that for this project and also how it ties to core data, sidewalk core data and the information gained from Lafitte and/or Blackbeard West or Davy Jones?

John Daniel Schiller

Yes. I think I covered a lot of that in opening but real quick. We have 300-foot gross interval there is also a -- it's all highly resistive. We have 120 foot of rib chord. We have indications from the course and analysis that it's a fractured carbonate. Others, some of your largest producing wells in the world. Unfortunately, there are not a lot you can do except put them on production so that they're going to flow. We've done pretty much all in-house as we can do, and that's just how fractured carbonates work. So we're running a slotted liner right now as we speak. We'll get that in the hole we'll temporary abandon a well and drill that line up again for completion. At -- and by the way, those may be some of the deepest conventional cores ever taken, 260-foot cores were down there 100% recovery on both of them. Over at Lafitte, we were able to use pressure tools there, give us pressure readings. We were able to get rotary cores. I think we've successfully covered like 19 rotary cores so we have that data, and all of that data put together in the Cris-R tells us we feel very confident. They're going to see some excellent flow rate out of the Cris-R sand there.

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

Okay. And then in terms of, as you look at the timing of the Lafitte and/or Blackbeard East, where would those flow into moving to the production stage? I'm assuming you'd go Davy Jones and then you'd have the Blackbeard West the #3 well but in just in terms of what an outlook as you look out over the next couple of years, because there should be a couple of big real big drivers?

John Daniel Schiller

Yes, I mean, I think if I was just laying out timing, I'd say Davy Jones 2; Blackbeard West, Lafitte and Blackbeard East are kind of the completion order. Some of them will occur within the next 12 months, some of them may take 2 years. Some of it is depending on what we decide to do 4.5-inch versus 3.5. 3.5 is what we've already designed and so we're working all that right now but that's kind of roughly the order of the completion as I've seen for that.

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

Okay. And then Blackbeard West, is that something based because you can complete it conventionally that can be even more fast-tracked via some sort of post facility?

John Daniel Schiller

Yes. That's why I think you bring it on even as convention drilling and the pay is right there below the Salt Weld, you're probably bringing in on around the same time as Davy Jones 2 or maybe a little later depending on what we have to do in the facility.

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

Okay. And then lastly, just when you talk about the 65% to 70% oil over the remainder of the year, I'm assuming that you all moved Davy Jones all the way to year fiscal fourth quarter, and so really more of that cash jump would be in the fourth quarter and not so much in the first, I mean, the third?

John Daniel Schiller

Correct.

Operator

And our next question comes from the line of Richard Tullis from Capital One South.

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

Did you mention what current production is, John?

John Daniel Schiller

Current production, we've been looking a lot of range around but our capacity is running 45%, 46%, somewhere near. There's days we make 39%, there's day we make 43%. So it's kind of pretty good. Looks like, we got several big completions going on right now so that's going to change that number pretty quickly.

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

And those are, I guess, you got the Magnum due in March and I guess South Tim in March as well. What are the big projects do you have that you expect online in the second half?

John Daniel Schiller

We should bring on Magnum, Winters and Camshaft this quarter. Bullfrog's next quarter and the other drill well is behind there from Miller to Costello and Pi, all those start coming on second quarter or fourth quarter our fiscal year.

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

Great. Great. Okay. I noticed the CapEx went up slightly for the fiscal year. I guess you're looking at a range of $450 million to $500 million versus, I guess $450 million previously. Is that mainly related to McMoRan ultra-deep spending?

John Daniel Schiller

Actually, it's a combination. Some of it's related to Bullfrog and what's going on there. Some of it is actually Creek. Rig rates have moved surprisingly. Some of the private guys have found oil costs to extra drill so we've actually seen some pressure whether it's long term or short term, none of us seem to be able to tell you right now. But there is some demand for the rigs so the rigs have gone up. And then as we re-evaluated some of the wells that we had in the budget early, we've kind of changed the nature of a couple of them so their cost plus the impact of the wider rig costs. So it's about half due to overruns and half changing costs.

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

Okay. How much is Lafitte up to at this point, gross cost?

John Daniel Schiller

Richard, what's your next question? We'll shout it out at you once we got it. We have the net number in the release. I don't know the gross.

Operator

And our next question comes from the line of Joan Lappin of Gramercy Capital.

Joan E. Lappin - Gramercy Capital Management Corp.

How many development wells do you think you will be drilling with McMoRan a year from now?

John Daniel Schiller

A year from now, I would say that we can probably have a rig running at Davy Jones, and we probably have a rig running at Lafitte so I'd say 2 development wells, 1 or 2 exploration wells.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. Now I want to understand what you're saying about Blackbeard East. You're running a liner but then you're going to temporarily abandon it. So what are the steps that are going into the thinking process on that well at this time?

John Daniel Schiller

Well, you're sand is down below 32,000 feet so we're running a slotted liner. Clearly, on a fractured carbonate you don't want to put seamen across the fractures. If it were shallower, you would actually consider what we call an open hoe completion, not even run the liner across it but at this depth, we're not sure that's a smart thing to do so we're going to run the slotted liner. After that, Joan, you got to evaluate the pressures and temperatures and decide, this could very well be the first application for a 30,000-pound tree in safety valve, which means we have to go through the same design process we did on Davy Jones #1.

Joan E. Lappin - Gramercy Capital Management Corp.

Will it take a year again for that?

John Daniel Schiller

It could take 2 years. That's -- we're looking through all that, but a lot of that's going to be somewhat dependent on what we learned from Davy Jones flowing also because there's some clerical parts and assumptions with regards to flowing temperature. For instance, remember, we built a 30,000-pound tree for Davy Jones #1, that's derated the 25,000 pounds based on an expected 400 degrees Fahrenheit flowing well head temperature. If we don't see those kind of temperatures, then all of that top [ph] models, okay, if we don't see those kind of temperatures, we may already have our tree built, and we just have to concentrate on the safety valve. So there's a lot of different pieces we're going to learn as we flow Davy Jones.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. So a few weeks ago, I guess when Jim Bob had his call, I thought they said maybe 3 weeks. And then now, it's turning into maybe 3 months or 2.5. And so I'm wondering, is it just because that piece of tool got stuck and everybody doesn't want to say anything because then we all get mad at you? Or is it -- it's really slowing down? And you also made a comment at the beginning about this is very expensive liner. And I know you showed us some of the stainless steel stuff last year at your Analyst Day. So what is the significance of what seems to be slowing down here?

John Daniel Schiller

Yes. Joan, look, since Jim Bob talked, we've actually met a lot of headway. We've cleaned up the wellbore. We've displaced our fluid. We're moving down the completion world. We're actually ahead of the schedule from a week ago even. My comment on the tubulars is they're high-dollar tubulars so you're a little bit more careful about the makeup of each joint so we're at -- we were running a normal well for us, we might run tubulars on the thousand feet an hour. This is probably going to be 1,000 feet every 6 hours or so. It's not going to be a quite as fast to make up but we're still talking hours, not days. If things go really well, we can move up but we want to give ourselves some time for any hiccups that might occur and/or just for the actual flowing and testing of the well to give ourselves some time to evaluate what we have.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. Can you talk about what expectations you have built into your assumptions on liquids in what's going to come up Davy?

John Daniel Schiller

Yes, I'd say, Joan, we've run our cases from dry gas. We've run sensitivities on condensate. We've run sensitivities on natural gas liquids. I would say that half the partnership thinks that you could have BTU gas in 1,150, 1,200 half thinks it's going to be 100% methane. We're going places no one's been before so again, we just have to see it flow. What I can tell you is if I take dry gas, I take decline on my production day 1 and I sell it for $3 flat, I'm still making a decent rate of return.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. So since you brought up prices, can you -- you guys have been superb on hedging. Hats off to West on that. And can you talk about what you're thinking is going forward now? Do you think gas prices are going to stay this low? Do you think they're going to go up? I'm sure it doesn't help you if it was above 50 degrees here in New York City last night at 10:00, on both gas and oil.

John Daniel Schiller

Yes, I mean, I'll tell you, we're going to continue to do what we've been doing, which is look to protect the downside out 18 months to 36 months from now. We may pay some dollars and treat it as insurance to do that, but we want to make sure we have the downside protected and an unlimited upside, given all the things that go on around the world today, particularly in the Middle East. From a gas side, internally, what we're looking at, we're going to watch the rig reports the next few weeks. I got to believe people are going to start shutting down onshore gas drilling. If they're not, then I think there's some things driving that drilling such as other people's money being spent versus the guy drilling the well. And if that's the case, then I think you'd stay down here for a longer period of time. And we're lucky we're 72% oil. It really is, I hate to say round off, but if we miss by 24 million cubic feet of gas for a year, that EBITDA impact is just not that much right now. And Richard, the number is close to $200 million on Lafitte.

Operator

[Operator Instructions] Our next question comes from the line of Mike Kelly of Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Wanted to just take a look at the realized prices that you had in the quarter. It looks like a pretty considerable step up versus the prior 3 quarters. I've got you -- your unhedged oil prices coming in at 116% of WTI versus the previous 3 quarters at 103% of WTI. Just wondering can you comment on what drove that increase and if it's sustainable going forward?

John Daniel Schiller

Yes, obviously, a large piece with the spread disconnect between WTI and all other grades of crude, and then in our case in particular, the heavy Louisiana sweet is starting to get about a $4 barrel premium to Louisiana LLI. And that apparently, we don't refine nor do we pretend to but apparently, a function of diesel demand, to export diesel and heavy crude makes more additional product in the light. So today, Brent is back up to a $15 spread comp month, it's moving out again 2 and 3 years out. So watch the spread, look at HLS versus LLS. And those will be your clues to how much we price. But if you're tracking us by WTI, you're going to be totally lost. That much, I'll promise you. Track us by Brent, you'll be a lot closer.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. I mean it does look like there was a significant jump on quarter-over-quarter in terms of, even if we're looking at Brent, you were much closer to Brent this quarter versus previous quarters. Is there an explanation for that or maybe we could follow up on this off-line but it seems like it was meaningful.

John Daniel Schiller

Yes, I mean some of it was the physical hedges that we had in place. As the spreads came down, we were closer with our physical hedges to where the actual spread was between Brent and WTI, and I think that's part of it. But Stewart can follow up with you more online.

Operator

And our next question comes from the line of Robert Ferer of KeyBanc Capital.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

This is actually David Deckelbaum. Just wanted to -- you guys have been fairly opportunity-rich looking out, I guess, some of the CapEx here, $450 million, $500 million, what are you all thinking now for sort of rig activity over the next -- as we exit, I guess, the fiscal year and as you go towards that board meeting in the summer? And are you comfortable with current rig activity or would you look to accelerate, take advantage of certainly the HLS premiums that you're receiving right now?

John Daniel Schiller

Yes, we'll have as we go towards the summer and end of our fiscal year, we're going to have 4 rigs run and operated. We're going to be picking up both the well in EXL 3 as it finishes up Davy Jones. And the EXL 4 that Apache has right now, hopefully get over some Exxon and some of our own platforms. I think that's a conversation we'll be looking at. Obviously, one of those is a platform rig at West Delta so you reach a point there, I think we only have 9 slots that we can drill. We've got 4 wells scheduled right now so we can maybe keep that work, and obviously, in this environment -- and that's what the guys are looking to do. And then I wouldn't be surprised if we keep that rig out there for the entire 9 wells based -- that's a field with 7,000-acre F-35 sand reservoir that's got a lot of oil in place and potentially using horizontal and some other things. But I think 4 to 5 operated rigs is probably going to be sort of the max number we'll run.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. I guess is there anything in terms of -- just -- could you comment at all on the permitting situation right now? And if there's any risk to your program from permitting delays?

John Daniel Schiller

There's very little risk from permitting delays. We -- what they could do to us, they've done. We now have to do worst-case discharge on all our wells even our sidetracks but we've got all of that taken care of. That was a little bit of the reason we didn't get the program started as early as we wanted. So I think permitting is not an issue. We continue to be chapped over a couple of things. They were kind enough to tell us today that they're not going to charge us $16,000 every time they inspect a rig and little things like that where it's just -- again, it's meaningless money but it's the whole attitude that we -- they take our royalties, they take our taxpayer money and yet, we still need to pay them to come make sure we're being safe. But that's the type of things we deal with. Remember South Pass 49, we're still waiting for them to give us a reply to our ability to put a platform rig out there. That's a significant loss of royalties to our government. We've got a lot of good oil wells there to drill, identified some amazing looking things on seismic. And we can't get to them because we can't get them to tell us that they're going to allow putting a platform rig on the platform. So that's where we get frustrated. Permitting itself is not an issue.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay, great. And lastly, just a quick question on the Sunny well. What do you guys have to see, I guess, from the B-4 and C-4 sands in terms of flow before you make the zone change to the original C-2 target? And how simple is that zone changed?

John Daniel Schiller

Well, the zone change is simple but understand, we found more oil than we thought we would so those 2 wells are making 1,400 barrels oil a day and we'll continue to flow them until they get 100% water or less than 20 barrels oil a day. Then for about $50,000 on the long strain will make a slide and sleeve and set up -- close a slide and sleeve, open a slide and sleeve and put the C-2 on. I think the main point of that is we drill the well for the C-2 and we're actually producing the [indiscernible] that came with it.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

I just want to confirm that, that was a pretty seamless process. I know you guys have explicitly said that a wireline operation, just wanted to know how seamless that would be.

John Daniel Schiller

Yes, David. All of our reserves are in what we call the Proved Developed Non-producing category, are just like this. We spend all the money for the gravel pack, we pump the gravel pack, the zones set up. All we have to do when the zone below it waters out, or depletes in a few cases, is we close that slide and sleeve on that zone. If it doesn't work, we'll set a bridge plug in the tubulars, they come up, we open the next slide and sleeve. If for some reason, the slide and sleeve doesn't work, we punch holes. But it's fairly routine, we do a bunch of them every year and them actually are going to cost us, in a worse case, is $100,000, a lot of times, we do it cheaper than that.

Operator

And our next question comes from the line of Jeff Hayden of Rodman.

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

John, several questions with a couple of follow-ups, I guess. One, kind of follow-up to Ron's question. I may have misheard you. When you're talking about the completion for Lafitte then maybe Blackbeard East, did I hear you say one of those could be about the same time as a second well in Davy?

John Daniel Schiller

Yes, what we're saying is the well we're drilling right now at Blackbeard. If they get some of those tubular sands, the Miocene sands on the tubular right below the Salt Weld, then we find production there that we can bring online with conventional equipment, you could move it along pretty quick. But I also have to tell you I'm not 100% sure what the facility situation is there.

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

Okay, got you. And then I'm kind of looking at CapEx going forward. I mean, I know you've thrown out a number in the past of kind of $600 million is sort of what you guys could do on a go forward basis or a level you'd like to get to. I mean, just kind of looking at your production, I mean, forecasted cash flow should be a couple of hundred million dollars above that on an annual basis. Can you guys or would you guys be willing to kind of run faster than that? Or could that maybe create some inefficiencies? I mean, how aggressive could you guys bid on your properties given how much cash flow you're going to be spinning off?

John Daniel Schiller

Yes, it's funny when get off this call that's exactly what we're getting ready to get over with on our board. Our strat plan, it kind of shows the different cases and we run from maintaining a low level of CapEx at $400 million, $450 million, to an aggressive case where we go $750 million, $900 million 2 years out. Obviously, I wouldn't be showing my board that, if I don't think we could do it so that's the high end. Whether it makes sense or not the way it's moving to quick is what we got to go through. You solve the high intakes by hiring more people basically to make sure that you maintain efficiencies around your drilling and your prospect opportunities.

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

Okay. And I mean, looking at the portfolio, you feel free that you don't punt on this if you don't want to answer it. But assuming you were still kind of ramp up that sort of high gauge $750 million, $800 million, $900 million of annual CapEx, looking at your opportunity set, on average, what kind of organic growth rates do you think that could deliver?

John Daniel Schiller

Yes, I mean, the high case gets you 25%.

Operator

And our next question comes from the line of Eric Anderson of Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

John, I wanted to ask you if you were at all surprised to find carbonates in the Sparta?

John Daniel Schiller

The answer would be a little bit, yes. It -- we didn't think there were carbonates over at Davy Jones but now we don't really know. It's a different look in the logs so anything's possible. But once we saw in the core, a little bit surprised but at the same time, remember that's what we were chasing at Davy Jones 2, the Cretaceous play. And as I've said many times probably the most productive reservoirs in the world are Cretaceous -- are carbonate sand or carbonate limestones. I'd say...

Eric B. Anderson - Hartford Financial Management, Inc.

Both of those are about the same depth between the 2 wells?

John Daniel Schiller

No. We're deeper over here from that Davy Jones. Right. But we're clearly -- I mean, what we do know is if you go through our whole geological assumptions right now and how you guys so much [indiscernible] everywhere else, you have -- we believe that [indiscernible] is more like a lake. It didn't have a lot of water in it. So you have the potential for the pipe with shallow water environments that are necessary for carbonates. And then there's other ways for carbonates to form too. So I think that's some of the things we're still studying, Eric. We're not going to tell you that we understand it. We'll say it's an interesting core and a lot of fractures in it.

Eric B. Anderson - Hartford Financial Management, Inc.

So based on the correlations that you've got between Blackbeard East and Lafitte, would you expect to see some part or all of what you saw at the bottom of Blackbeard East in the final thousand feet of Lafitte?

John Daniel Schiller

Well, that's what we're going to find out. I mean, we correlate the Frio sands pretty good. We have Frio, and then there's a layer of sand, and then you go down into the Eocene where you find the Sparta, and obviously, we wouldn't be drilling ahead if we didn't think we we're going to see it over there. And we'll find out here shortly. And we've been actually making pretty good hole there we got a trip to spin out but we should be getting interesting fairly quick.

Eric B. Anderson - Hartford Financial Management, Inc.

Okay. My final question is what do you attribute the sort of record speed that you've been able to achieve that Blackbeard West #2 or #3? And you're down to what almost 17,000 now?

John Daniel Schiller

Down to what?

Eric B. Anderson - Hartford Financial Management, Inc.

17,000 feet?

John Daniel Schiller

No we have a little bit shallow 16,000. But yes, I think it's kind of what all laid out. McMoRan is going with some smaller holes up top, which allows them to drill down quicker, allows them to get primary seem [ph] that job, some of the things that were hanging us up early on. So the next pipe points at 19,000, they get that into the ground and get a primary [indiscernible] job, then we continue to pick up some days. So let's just see how it goes. But we're taking advantage of drilling smaller holes up top and using more expandable liners so where we still get big -- the casings completions we wanted TD, but we don't drill as much rock getting there.

Operator

And our next question comes from the line of Dan Texas [ph] of Morgan Stanley.

Unknown Analyst

Since you acquired the ExxonMobil assets, you've paid down a lot of debt and at least, I have leveraged right now at 1.4x that's down significantly. Yet this week, Moody's affirms you at Caa1 versus the other 2 agencies at B. Can you comment on what you think at this point is going to take on upgrade?

David West Griffin

I don't really know. We have a fairly active conversation with Moody's. They do have this -- they have a very detailed pricing grid that they published and include as part of the report. I think we're the only Gulf of Mexico player that's actually rated 3 notches below where the indicative rating is. I think it's something that over time, as we bring on additional volumes, that -- their criteria is largely related to size so as we bring on additional volumes we book some reserves on Davy Jones as well as have some additional reserves brought all those are size related so I think that eventually they'll have to reassess where they have Energy XXI.

Operator

And we also have a question from the line of Joan Lappin of Gramercy Capital.

Joan E. Lappin - Gramercy Capital Management Corp.

I wanted to ask about Creek, you mentioned that this morning, which you haven't done in several quarters. So could you bring us up-to-date on Creek?

John Daniel Schiller

I didn't mention it.

Joan E. Lappin - Gramercy Capital Management Corp.

I thought you did.

John Daniel Schiller

I don't think so. But if I did, let's just say we're waiting on our government in some form or fashion and leave it at that, Joan.

Operator

And that concludes our question-and-answer session for today. I'd like to turn the conference back over to Energy XXI for any final comments.

John Daniel Schiller

All right. Thank you, everyone. We really appreciate your showing up for the call and listening to us today. It's going to be a great quarter coming ahead still. Things look good and we'll continue to deliver for you every day like we've been doing. So thank you very much.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This does conclude the program, and you may now disconnect. Everyone, have a good day.

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

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

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

Source: Energy XXI (Bermuda) Limited's CEO Discusses Q2 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts