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Energy XXI (Bermuda) Limited (EXXI)

Q4 2012 Earnings Call

August 09, 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

Ben Marchive - Executive Vice President of Exploration and Development

Nelson Steve

Analysts

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Mark Lear - Crédit Suisse AG, Research Division

Joseph Patrick Magner - Macquarie Research

Michael Kelly - Global Hunter Securities, LLC, Research Division

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Joan E. Lappin - Gramercy Capital Management Corp.

Jeffrey Hayden

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Energy XXI Fiscal Fourth Quarter 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, everyone. Presenting today, we have John Schiller, Chairman, Founder, CEO; and West Griffin, Chief Financial Officer; Ben Marchive, Executive Vice President of Exploration and Production. We'll be available to answer 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 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 latest 10-Q and the forthcoming 10-K to become better familiar with these risks and our company.

Now I'll turn it over to John.

John Daniel Schiller

Thanks, Stewart. Welcome, everyone. Our fourth quarter and year-end financials were released at the close of business yesterday. We have record production of 47,600 barrels of oil equivalent per day for the quarter, producing nearly 70% oil. For the year, we averaged more than 44,000 barrels of oil equivalent a day, up 27% year-on-year. Our net realized crude price for the quarter was above $108 a barrel. Oil continues to drive our financial success, generating free cash flow that has bolstered the balance sheet and allowed us to deliver dividends to our shareholders.

Last, we're going with some of the financial highlights in a few moments. Let's quickly review the fiscal 2012 year. We've set out with a budget focused on capturing the low hanging fruits from the acquired ExxonMobil assets. The primary goal is to maximize free cash flow to reduce the leverage we used to buy the properties. What we did was exactly that. We drilled 11 development wells, recompleted 32 wells. We increased oil production 30% year-over-year during a period of healthy commodity prices and delivered a record $4.10 per share in earnings. More importantly, we generated a record $850 million in EBITDA, which allowed us to slash net debt by over $180 million, taking the long-term net debt to cap ratio from 53% down to 39%, achieving our objective of getting our debt to cap below 40%. That's more than 3 percentage points a quarter. Even with the low-risk development focus, without a single high-impact exploration well outside the ultra-deep partnership, we also successfully replaced all of the year's production and grew up for the reserves.

Now in still estimated year-end proved reserves at 120 million barrels equivalent, additions and revisions totaled more than 21 million barrels of oil equivalent, which replaced 132% of our production. We had some companies drop off the book causing 5-year low, but they're on top as we hold our production, so we'll get to those eventually. Even with that, we replaced nearly 120% of production and grew reserves 3% organically without an acquisition or any bookings from exploration.

Even more important is the continued concentration on oil. We replaced 168% of our oil produced for the year, all percentages increased every year since the company was founded and made a leap last year to 71% of our proved reserves. That only focus continues to drive our PV-10, which jumped nearly $1 billion to $4.3 billion on proved reserves alone. The end result is that our proved-only SEC PV-10 value is significantly above our total market capitalization. Looked at another way and judging for net debt, the proved-only PV-10 at $39 a share. As we've shown, we have a good track record with efficiently converting probables and possibles to proved. We have repeatedly demonstrated in the 6-year history of our company that the unbooked upside of our core properties is real.

This year, we'll spend the bulk of our capital to continue to develop our properties while spending approximately 15% on some key exploration wells that can move the reserve real meaningfully. Another subtle change is the focus for our activity is our efforts to increase recoveries from our existing producing reservoirs using horizontal wells and pressure support. Then we'll expand on this more as we discuss the fiscal 2013 plan in a few minutes. But first, I'd like to have West review some of the highlights from the last quarter, end of fiscal year.

David West Griffin

Thanks, John. Let's start with production. Globe volumes have continued to trend upward, increasing 30% year-over-year versus our overall growth in volumes of 27%, reflecting the oil focus of our capital program. The June quarter and full year averages were new records for Energy XXI. During the quarter, tropical storm Debby deferred about 2,000 barrels a day for the quarter. Pipeline downtime accounted for another 1,200 barrels a day. Last week, we reported production averaging about 45,000 barrels a day, still impacted by about 5,000 barrels a day of downtime. And we provided detail on the Carinos, Don Tomas and Pi wells that should add approximately 6,500 barrels a day to volumes in the near term. Approximately 92% of the liquids we produced are crude oil, which helps our average realized price. As John mentioned, for the fourth quarter, our realized price per barrel was $108.37 and for the fiscal year, it was over $106. While you consider our production mix is nearly 70% oil, that means that 94% of our pre-hedge revenues came from oil in the June quarter.

Our EBITDA per barrel continue to be a healthy $51.47 per barrel. This broke record annual revenues to over $1.3 billion and EBITDA to more than $850 million. Our LOE was up slightly last year, mainly due to additional work over maintenance expenses. As volumes increase, LOE should come down this year to about $16 per barrel, as John mentioned during our Investor Day in June.

Moving onto our liquidity position, Slide 11 shows our progress paying down the revolver and building a cash balance. In fiscal 2012, we reduced our long-term net debt to cap to 39% from 53% at the start of the year. Absent an acquisition, we expect to continue reducing net debt by stockpiling cash as the first bonds are not callable until December 2014.

CapEx including P&A for the fourth quarter was $185 million, bringing the full year total to $591 million as we ramped up rig activity to get a running start on the new year. We're currently running 4 operated rigs and participating in 3 non-operated rigs; 1 with Apache and 2 with McMoRan.

Our fiscal 2013 capital budget of $700 million is focused on development activity, with only 15% of the budget spent on exploration. This keeps the overall risk profile relatively low as we've added some high-potential exploration within our core properties. The ultra-deep partnership with McMoRan is targeting both exploration and the development of our discoveries, with a budget of $94 million this fiscal year. Now I'll turn the call to Ben to elaborate on some of that activity. Ben?

Ben Marchive

Thanks, West. As West just said, a majority of our CapEx, now focused again in the current fiscal year, will be on the development of our assets. We still have a lot of low hanging fruit from the properties that we acquired from ExxonMobil, and we continue to find opportunities in our legacy fields to draw production growth again this year. For example, results from Main Pass field has been outstanding. As we outlined in our operations update last week, we successfully tested low-resistivity pay in the Carinos well and we just finished completing Don Tomas, which looks like a big well that could deliver in excess of 3,000 barrels of oil a day. As we speak, the well is unloading so we should have more data next week when we present it on Monday at Enercom. Going forward, at Main Pass, we have an additional 5 wells drilling program, a 4-well recompletion program and expect to spud our first of 2 expiration wells there in January time frame.

At West Delta, Rosebank is now fully online and producing about 1,000 barrels of oil per day equivalent. This well was a vertical well targeting the F40 sand, which is very productive in the field. The well began initial testing in early July, but due to rig movements, did not come fully online until last week. Also, on West Delta, we had spud our first horizontal well, Big Sky 2. The pilot hole has been drilled and logged 67 feet of measured -- measured debt pay in the F30 sand. The well will be sidetracked and that 1,000-foot horizontal section will be drilled through the F30 sand and completed. We expect to drill 5 or 6 horizontal wells in the field this year. At our recent Investor Day, we showed how a typical horizontal well should deliver 3x to 5x estimated ultimate recovered per well with only a 15% increase in well cost. That's based on historical results. Completion technology has come a long way since those were done, so we believe our horizontal program could yield even better results.

At Grand Isle, we have a number of wells on the schedule this fiscal year. We expect to drill as many as 6 development wells, recomplete another 5 or 6 wells. We are currently testing Pi, which we logged pay that exceeded our pre-drill estimates. The well was completed as a single completion when we expect to reach 1,200 barrels of oil equivalent per day.

Currently, we are unloading the well producing approximately 900 barrels of oil equivalent per day with 1,850 PSI flowing tubing pressures, so we have room to ramp up that rate.

At South Timbalier, in 54, we have logged the first pay section as Sparkplug. Initial wire line log indicates 60 feet of oil a day in H1 sand. We plan to set casing there and drill another 900 feet or so to TD, logging base 3P sand. Again, this is another example of our typical development drill well program, solid pay, low-risk drilling.

On a more general note, John mentioned our efforts to increase recovery from our existing 4 fields. This is something we started giving a little detail on at our Investor Day. I already talked about the horizontal drilling program, which is one good way to increase recovery. The other is by enhancing the water dry within a producing reservoir such as by drilling water injection wells down dip. Those costs, including water handling facility are included in the development capital we showed in the earlier slide. The most common question we've gotten since we started talking about these efforts is, if it's so easy, why isn't everyone doing it in the Gulf of Mexico? The simple answer is, that you have to own and operate the big old oilfields to make it work best. We have 5 of the top 11 discovered oil -- discovered on the shelf, and the majors have most of the rest, and 8 major has most of the rest. Looking at our top 5, those fields have produced a cumulative 1 billion barrels of oil with 38 million barrels still to go. Importantly though, the original oil in place in those fields was about 2.3 billion barrels so recovery factors average about 40% -- around 45%. For these types of reservoirs, it's not at all uncommon to achieve 60%, 65% or even 70% recovery. If we can increase our recovery to just 50% from the top 5 fields, we can nearly double our current reserve base. This is what we've talked about when we say the next 5%. Remember, that's not talking about expanding the size of the field by proving up adjacent ball blocks or whatever, it's simply a matter of flushing more oil out of existing producing reservoirs. We look forward to reporting progress on these efforts as we proceed. Now let me turn it back over to John to wrap it up.

John Daniel Schiller

Thanks, Ben. As you can tell, we're excited about the core development program, what we're able to deliver last year and what we expect to achieve this year through a combination of exploration and enhanced oil recoveries. We're already off to a great start with both Don Tomas, giving us significant reserve adds towards our repricing production target for this year, as well as the Pi well, which is sitting right on top of the H3 Sand after we run this pipe and both of those would be nice to have for the company. Another side of the business is the D part of our business, so let me give you some updates there. [indiscernible], we're drilling a hole in our LWD, we continue to fight the whole frac-ing off a little bit there, but we've increased our [indiscernible] in good shape. We want to watch the bottom of the LWD and the bottom right now is about 21,431 or about 200 feet shy of seeing the whole section on the log. And so we hope to wash that with this LWD and then proceed to drill ahead. Davy Jones, we have rigged up the core team unit. We're drilling a hole right now, circulating around good mud. We're about 15,000 feet and continue to go in. Once the well is dead and we have good solid [indiscernible] around we'll throw out a hole with our tubing, run back with new seals and look to bring the well online. Our last well, the Chevron, [indiscernible], continue to make great hole at the Lineham Creek, we're actually coming up on 21,000 feet there. So the ultra-deep program is making headway sometimes slowly, but we continue to be very excited about the overall impact and think that the new flow will be pretty good during the month of August. With that, I'd like to turn it back to the operator to the operator to open up lines for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of Duane Grubert from Susquehanna Financial.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

John, in the past, you've talked about the plausible availability of some of the private sellers for various reasons. Can you walk us through why we haven't seen more deals maybe, and also if you would have any similar interest in picking up gas assets along the same thinking?

John Daniel Schiller

Duane, I think the key thing that's going on right now, we've seen a fair amount of assets for sale a lot in private, some public companies selling pieces. I think you're coming in a state right now where you had oil prices fall off and come back, gas prices clearly have leveled off. So we kind of -- in a market, I think right now where people, both buyers and sellers can come to agreement on some deals. So I think you're going to start seeing things rebound and hope that thing will pick up a little bit. We continue to look at a lot of things both on the gas side and on the oil side. And we'll just see what happens.

Duane Grubert - Susquehanna Financial Group, LLLP, Research Division

And then clearly, the investors are happy about your free cash flow status, but you do have this cash sitting on the balance sheet and some time before you can do anything with it in terms of debt payback. So how do you think through stepping up your activity levels versus just letting that cash sit there and what else might you do with it?

John Daniel Schiller

We need to know -- we spoke many times about $700 million sort of be in the maximum efficiency CapEx that we can do with operations. So we're always looking at how we improve our batting average for that $700 million. And you'll see throughout the year again while we make changes within the drilling program to take advantage of things we're learning during the year. My guess this year that not many more horizontal wells, that may mean we move around some of the exploration wells. We'll just see how it goes as we get into it. And then the other end is we've got free cash flow and we see some acquisitions up there that we think are very accretive to the company and step right into our operating base, we'll be looking to make some of the those things happen.

Operator

And our next question comes from the line of Michael Glick from Johnson Rice.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Just on the production side, how should we think about your ramp throughout the year to kind of get you to that 58,000 to 62,000 barrel a day guidance range?

John Daniel Schiller

I think from a production ramp standpoint, this quarter will be sort of flat-on-flat. It's all going to depend on whether we're getting any storms in, and with some of our model downtime, if we get lucky, no storms come, we could have some growth. And then, as the new wells are kicking in, we start getting full quarter growth from the second quarter. That's where you always start seeing the ramp-up occur. And we worked the number hard the last 2 or 3 weeks and feel very good about the guidance range that we've given you for the year.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

Should we expect that similar oil mix going forward from what you had in the fourth quarter?

John Daniel Schiller

Yes, I think what we've been talking about, Michael, ever since even before the Investor Day, but our variability is going to come from the high rate gas wells. For instance, if you actually looked at our volumes for this -- all the way back a year ago from the budgeted fourth quarter, we're actually ahead of our oil volumes, but the gas volumes are a huge risk because of high rate gas wells, because some of them didn't get drilled and some of them didn't come in. But I think what you'll see is that we start making big headway on the volumes that will probably be because we brought on a high rate gas log or two. But in aggregate, the growth comes and the revenue growth comes from the oil properties.

Michael A. Glick - Johnson Rice & Company, L.L.C., Research Division

And then just shifting to the horizontal drilling side, what are the conditions necessary that has to be present for you guys to pursue horizontal wells, the sand thickness or maybe you could just give us some more color that?

John Daniel Schiller

Yes. I mean, I would say the biggest thing is there's really 2 or 3 potential applications. The first and easiest, the least complicated is what we're doing right now, which is we have a really big structure out of West Delta 73, big being 3,000 to 4,000 acres of closure, very little elevation change across it, about a 200-foot total drop in top of the structure to the bottom. And so that gives you a nice, smooth water. We've got decent water support so you just lay horizontal ends towards the top of those structures and start bringing all that oil to you. And all you're doing is slowly but surely reducing that residual at the bottom of the oil column from 20% to 15%. So those are the first ones we're targeting. Next we go after what I'll call the semi-strong water drives where maybe you start it with 4,000 pounds pressure and now you got 2,500. There, we basically do the same thing. You don't have as much flow rate and we'll be looking, can we get some water into the ground through injection spots to pick up that pressure. And then the ones that offer you the most ultimate recovery but involve the most capital are your pressure depletion reservoirs, which we have a few like in Main Pass 61, where we already have a water injection program going there, where you go into some depleted sands that are probably only giving you 15% to 20% recovery. You lay horizontals at top, start injecting water at the bottom, you try to move more fluid through there and double that recovery from the revenue. So those are the 3 [indiscernible] areas we're targeting. We're starting, Michael, with the strong water drives that's we think will just be in 500-, to 1,000-foot horizontal at the top and move the fluid.

Operator

And our next question comes from the line of Mark Lear from Credit Suisse.

Mark Lear - Crédit Suisse AG, Research Division

Looking at the reserve growth in 2012, I know you guys were really focused on getting production up and focused on development, but when you're looking at your '13 program a little bit more exploration and mix, can you maybe give some color or guidance around what you'd expect for asset growth in 2013?

John Daniel Schiller

Yes. I mean, I would tell you that our target every year is basically to replace reserves and maybe 10% on top, with some luck like this year. But obviously, Mark, as we get closer to the ultra-deep [indiscernible] test out of Davy Jones, the stuff we'll do above Davy Jones 1 and 2 during the year starts in Blackbeard West. Hopefully with what we have going on there, all of those things start to have a significant impact. So we have some U.S. numbers, we clearly don't quote them very often, but obviously, with exploration success, we can have some big impacts on what our overall reserve replacement is and our ultimate reserves.

Mark Lear - Crédit Suisse AG, Research Division

Got you. And then with, I guess, some production down because of third-party pipeline maintenance, can you speak to what those volumes are and I guess when you expect that to be resolved?

John Daniel Schiller

Nelson can handle that.

Nelson Steve

Right now, we're shutting about 4,000 barrels so that has us down about 2,500 barrels along with Chevron and Bonita Pipeline. But our Bonita Pipeline was supposed to be coming back up today, so that tells us will be at the -- right after Labor Day so we should be getting it back here in about a month.

John Daniel Schiller

[indiscernible].

Nelson Steve

Yes.

Operator

[Operator Instructions] Our next question comes from the line of Joe Magner from our Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

I guess, sort of on the lines of what you just got done on target or the aims for the horizontal program, the drilling of down-dip water wells and the hope to improve recovery from some of those larger oilfields, is some of that actively planned for this year and how quickly would you expect to see an impact from drilling those wells?

John Daniel Schiller

Joe, I would say that we're doing a lot of looks with all our big reservoirs right now. And as I mentioned, obviously the first wells are going to target getting updip in strong water drives where we don't have to spend additional capital. There's some like what you're describing and we're looking at different ways to get the water into the reservoir. My guess is, we will try some of that this year, but it's kind of hard to give you a lot of detailed color on it.

Joseph Patrick Magner - Macquarie Research

Okay. And then, I guess, since the analyst meeting, can you maybe give us an update of your current line-up or rundown of some of the key wells that -- you touched on Don Thomas and Pi, but some of the other key wells that are on the schedule that will have an impact or move the needle on that growth ramp starting in sort of December quarter?

John Daniel Schiller

Yes. I mean, I think Don Tomas and Pi have already started things really good for us. It's hard to explain just how gorgeous that eyeball fit clean sand is, and we've already gotten pressure date and all, but fellows, it's pretty much virgin pressure. So we're going to have some great reserve out of there. Pi has been -- is going to be another good well for us. Sparkplug is running right where it's supposed to be and we still got the H3 sand, which is the main objective. So all those look good. I think all of the horizontals are going to have upside, Joe. It's hard to point to just one big well out of your development program. Obviously, on the exploration side, things like creeks that we've been waiting a lot of years for to get drilled will get drilled and that's going to have a lot of potential for us. We hope to get -- we've applied for a unit, hope to drill an updip well over at Laphroaig in Bayou Carlin where we're partners with McMoRan. So some of those wells are going to have high impact. And then obviously, just the exploration as we get it done. Most of exploration now is going to be sort of second half of the year, Joe. We're kind of front-end loading again. Some of it could tell by what kind of rigs we need and where we have the rigs in terms of when we can get some of the exploration done.

Operator

And our next question comes of the line of Mike Kelly from Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

I was hoping we'd get an update on the Blackbeard West Shallow trend. At your Analyst Day you seemed optimistic that the first well there could actually contain liquids. You mentioned you saw a condensate in the mud shaker. I'm just wondering if you had any update there? And also if that does possess liquids, how quickly you'd be able to fast-track the second well? I know you mentioned Barbosa was in the works.

John Daniel Schiller

I don't think any of that's really changed. As I said, we've been fighting hole conditions right below that salt. The well wants to keep packing off so we're up to a 19-pound mud, which seems to have fixed the problem. We just made a trip with the LWD, we're going back in the hole with LWD. We're about 230 feet off the bottom in terms of what we've seen with the log so far, so we want to get that log to the bottom. And then hopefully proceed with drilling ahead here. I think Jim Bob will give you a lot more color on it when he speaks at Intercom next week. But yes, we continue to think that we're in a perfect situation here. We have 2,500 foot of closure. The seal [ph] seems to be working. We would probably go to Barbosa next. It's conventional type equipment, 20,000 pounds at most, if not 15,000. Most likely 20,000 right now would be my guess, so that's right off the shelf. And you get production relatively quickly. So what we -- we're very excited about that well, we just don't have a lot of progress being made right now.

Operator

[Operator Instructions] Our next question comes from the line of Biju Perincheril from Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

I was hoping if you could reconcile your production? I think you in the last press release said we're in the mid-50s peak in the last quarter versus -- and the current levels are in the mid-40s?

John Daniel Schiller

Yes, you're cutting in and out, but I think you want to reconcile the peak rate of 56. Basically, it's about 3,000 barrels a day from pipeline downtimes, 1,000 barrels a day on our rig [indiscernible]. And then a large piece of that has come from Costello where we have very large gas rates at 24 million a day and that gas is falling off and making in the neighborhood of 1,000 barrels of oil a day, so we lost a lot of volumes there. But again, minimum impact on cash flow, more on the dollar, and then cash flow by 4.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. Okay. In the pipeline volumes, you've said it's going to be back on right after Labor Day? Did I hear that right or?

John Daniel Schiller

Yes, but the biggest one is we've known for, what, 3 years tops? So had to be working at South Pass 49 for it's kind of hard to plan much when they tell you, for 3 years, you're going to do it. So they finally gave us about 2 or 3 weeks head-up notice and they shut in our whole platform. So that was one that we do. There's nowhere budget it, there's nowhere to forecast it, it's been out there over our heads for 3 years and now it's getting done. So that's the majority of what we're missing right now from the pipeline.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. And then on the reserves, can you hit about 9 million barrels of a positive revision on the oil side? Can you break that out and how much of that is performance, and if there is any price-related revisions in there?

John Daniel Schiller

I think your question was positive revision on the oil, how much is performance versus price.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Correct. Right.

John Daniel Schiller

Price. We picked up very little price, Biju. Just the nature of our beast, we don't have a lot of price adjustments. It's not like we have 3% shallow decline out there that's going to be hammered. So I would tell you 90% is performance, 10% pricing.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

All right. And the performance is that the declines are shallower than initially forecasted, is that as simple as that or something else driving it?

David West Griffin

The decline is shallower. That's right, Biju. One of the things that we experience every year with [indiscernible] is they always have fairly conservative forecast of the oil production and forecasting more rapid decline in what quite honestly we typically experience. And that's the reason why virtually every single year, we have positive performance revisions on our oil.

John Daniel Schiller

I mean I believe what we're counting on. But you always have to look at [indiscernible] got a lot of oil like us at least on a 2P basis because so much of our reserves -- I can give you an example, Onyx was on the books at this time last year for 100,000 barrels of oil and made 1 million barrels during the year from the total proved reserves were 100,000 when we started. So a lot of those reserves in the 2P and 3P categories are moving in, and that's why for 6 years running now, we've had positive revisions every year including the years when we wrote down gas reserves on [indiscernible], and we still were positive overall because of conservative nature of how you had to book reserves in the Gulf of Mexico with regards to lowest known penetrations and all.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then one last question for me. Can you give us some ballpark numbers on the -- what's the contribution you expect from the horizontal wells production ratewise?

David West Griffin

Could you answer the question how much contribution from the horizontal wells and the overall number? 10%, ballpark [indiscernible]?

John Daniel Schiller

I think, overall, it's somewhere between 4,000 and 6,000 barrels a day for the year out of 60,000. And again, you will see how that works, that could be low or high. I think some of the wells will come on surprisingly high, some may come on surprisingly low. And we will see how they fall.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

And that's in sort of year-end number, not an average for the year, right? The 6,000 barrels?

John Daniel Schiller

That's the average impact for the year. It's about up to 10% of our midrange target of 60,000.

Operator

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

Joan E. Lappin - Gramercy Capital Management Corp.

I wonder if West can address -- you're starting to round up cash on your balance sheet and what is -- when is the soonest you can get rid of those expensive bonds, and that's number one. Number two is, to what extent have you been delayed by waiting for the Davy Jones rig to come over to you? And what impact does that going to have on you and when do you think you're getting it now?

John Daniel Schiller

I'll take the second question first, which impact the core [indiscernible]. One of the reasons we didn't make some of the volumes we thought we had made from years is because we've been waiting to go building that out for 6 months. We think we have that more or less corrected forecast for this year's volume. So assuming we get a well test in August, which I've seen nothing to say it won't get that done right now, then I think we correctly modeled our numbers for this year, which would start with a couple of recompletions with the rig and then go from there. With regards to bottom, Joan, West looks at it once every 2 weeks. The bank is coming there every week and tell us how cheap we could borrow money at. The problem is that the make-whole provision and everything else, it's just not very efficient use of our money to buy back the bonds. So we continue to look for acquisition opportunities where we do what we do best, which is not financial engineering but engineering the old-fashioned hard way and get production and reserves out of the ground. So I think we're cautiously optimistic that the right deal is going to come around and we'll continue to grow the company with what we're doing with our CapEx program, as well as with some M&A activity.

David West Griffin

Joan, to your question the 9 1/4% bonds, which are the most expensive bonds we have outstanding, those are callable in December 2014.

Joan E. Lappin - Gramercy Capital Management Corp.

So you got a long way to go on those?

John Daniel Schiller

Correct.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. So how is the recent dip in gas and oil prices affect what's on the market and available for you to buy? Has it increased, decreased [indiscernible] people want to wait until prices come back, or is it actually accelerating their interest in selling?

John Daniel Schiller

No. It's kind of interesting. I've always given the analog that all of a sudden you're working for someone in New York and your job is in Houston and you got kids in school and it's a summer and you want to get them down here, you're going to sell your house and buy a home and Houston, you don't care that much about the price of the home in New York because you made a decision to move to Houston. I still think that's the overwhelming thing driving the M&A market as people are making strategic changes that they want to concentrate one part of the world versus where they are today. They're spread out too far and need to consolidate. That's still from the packages we've seen. The #1 deal driver behind that is private company, private equity companies, private equity backed companies that are wanting to make some money and perhaps some of them are in oil and are not as comfortable on oil. So those are 1, 2 things I see. To a lesser extent, I think there are some deals coming to market less because of gas prices. But that's probably the third biggest driver of why people sell assets.

Joan E. Lappin - Gramercy Capital Management Corp.

I assume you don't want gas. And you're going to have [indiscernible] you're going to need to buy gas?

John Daniel Schiller

We think you said something about buying gas?

Joan E. Lappin - Gramercy Capital Management Corp.

I said I can't -- are you there? Can you hear me?

John Daniel Schiller

You're cutting in and out, Joan, but I think what you're asking, is would we buy gas? And I think as we've talked about we'd look at gas for the company's joint venture that we have with some shareholders, it depends on the quality of the gas. If it's something that we're just playing a price game on and we're just operating cheap and production is going to fall, then we're probably going to that in the joint venture off balance sheet. I do think there are some key gas assets that we believe have a lot development opportunities to them, and that will sort of near the bottom on gas prices so we could find someone that needed cash and we could buy out of some of the those opportunities. I think that is something we would look at.

Operator

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

Jeffrey Hayden

I guess just one quick one and then one clarification I may have missed it. So I guess first, when you guys looked at your probables and possibilities, you talked about, is there any impacts from the ultra-deep stuff in those numbers?

John Daniel Schiller

No. Continues to be nothing from the ultra-deep except in contingent resources.

Jeffrey Hayden

Okay, great. And I may have missed this one, John, and I apologize if I did. I know you guys -- you were kind of asked about kind of the Davy wells. Did you give any kind of updates on the timing of that process?

David West Griffin

Timing of what?

John Daniel Schiller

I think, Jeff, we're still in August. It could be late August right before Labor Day. But we're in there with [indiscernible] getting good mud displaced around. We'll pull out a hole in our production stream, lay it down, send it in, pick up the new packer production stream when it comes back and seals and running the hole -- and be ready to open the well up. So we got all good light. We're still at the end of this month. If there's any slippage in there, it could be in the first week of September. But it's a little too early to make that call. Right now, things are doing okay.

Operator

And our next question comes of the line of David Deckelbaum from KeyBanc Capital Markets.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Just wanted to get some color around the rig move situation. I'm wondering if we should be factoring in some more conservatism toward the back half of the year now? I guess, how strained do you feel? And I guess, adding onto that, you now found another rig to drill Golden Bear. I guess if there are further delays at Davy Jones, is there a contingency to find another rig and do you think you'd be able to find another rig to further the Grand Isle 16 program?

John Daniel Schiller

We've been talking with several of the operators on rigs. Magner and Nelson stay on top along with Ben, so I felt pretty comfortable going to actually we're going to execute the program that we have laid out for you. It may or may not occur in the same order as we currently show it depending on which rigs we can get and which rigs those wells are capable of drilling. The biggest part of the rig move was we had to swap the neighbor's rig over at West Delta from one end of the platform to the other, and that ended up being 3 plus, 4 weeks worth of work, which was a part of the next plan for. And that hurts.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Fair enough. And I guess, specifically, is there any updates that plans for Onyx this year in terms of drilling a second appraisal well or opening up one of the suites down-dip?

John Daniel Schiller

Yes. We're actually looking at that pretty hard. The guys at Schlumberger think they have a pretty decent reservoir match, so we're running some things against that match. It looks like we might shut in one of the wells like you're talking about that has started cutting water and go deeper there. And from the other reservoir where again we have very little booked. A lot of our efforts right now is going on over at the South Pass 49, and some of the big potential we showed you guys there were starting to do some rate completions in for the 65 sand that we've been told a lot of potential. That's the well where we're making 2 million a day, like a rock with continue pressure lock, with 60 barrels condensates. So we've got a lot of things going on I feel very good about, and it's going to be a good year.

Operator

And that concludes our question-and-answer session today. I'd like to turn the conference back to Mr. Schiller for any concluding remarks.

John Daniel Schiller

Thanks, everyone. We've got a great year behind us now. We look forward to be an even better year, with strong cash flow, year-on-year production growth and solid reserve adds. So thanks for listening. We'll see a bunch of you in the next couple of weeks either at Intercom or Barclays so safe travels, look forward seeing everybody.

Operator

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

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Source: Energy XXI (Bermuda) Limited Management Discusses Q4 2012 Results - Earnings Call Transcript
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