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Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

Q2 2014 Earnings Call

February 07, 2014 10:00 am ET

Executives

Stewart Lawrence - Vice President of Investor Relations & Communications

John Daniel Schiller - Chairman and Chief Executive Officer

David West Griffin - Chief Financial Officer

Analysts

Joseph Bachmann - Howard Weil Incorporated, Research Division

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

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

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

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

Brian W. Foote - Clarkson Capital Markets, Research Division

Stephen F. Berman - Canaccord Genuity, Research Division

William Christopher McDougall - Westlake Securities LLC, Research Division

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Joseph Patrick Magner - Macquarie Research

Michael Kelly - Global Hunter Securities, LLC, Research Division

John Polcari

Joseph D. Gibney - Capital One Securities, Inc., Research Division

Joan E. Lappin - Gramercy Capital Management Corp.

Jeffrey W. Robertson - Barclays Capital, Research Division

Operator

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Energy XXI Second Quarter 2014 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would like to hand the conference over to Mr. Stewart Lawrence, Vice President of Investor Relations. Please go ahead, sir.

Stewart Lawrence

All right. Thank you very much, and welcome to the call, everyone. Presenting this morning, we've got John Schiller, Chairman and CEO; and West Griffin, Chief Financial Officer. We'll be available, as always, to answer your questions at the end of the call.

Before we get started, I need to remind everybody 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 described in our earnings release issued yesterday 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 become better familiar with these risks and our company. Now I'll go ahead and turn the call over to John.

John Daniel Schiller

Thanks, Stewart, and welcome, everyone. Our second quarter financials were released yesterday evening. Production averaged 45,100 barrels equivalent a day for the quarter, and more importantly, we continue to grow our oil production for the third straight quarter. We've got a lot of exciting things going on in Energy XXI right now. Our horizontal program's delivering excellent results, and we're adding new facilities and upgrading existing facilities so that we can continue to take advantage of these economics.

On the exploration point, we will be completing 2 of our ultra-deep wells in the coming months, and we've spud the delineation well in our first sulfate discovery at Main Pass 295. I'm going to turn it over to West, now, to discuss financial details with you.

David West Griffin

Thanks. Let's take a look at quarter-over-quarter results. As John mentioned, our oil production rose for the third consecutive quarter, averaging 3,200 barrels a day. We continue to be highly levered to oil, and all of our development drilling targets oil, so the oil production mix should continue climbing.

Since oil accounts for about 90% of our revenue, higher oil volumes normally drive higher EBITDA. However, realized prices in the December quarter were a bit of an anomaly that hit results in a couple of ways.

Looking at the December quarter versus the September quarter, EBITDA was $37.5 million lower. Lower crude oil prices accounted for about $31.5 million of the difference. LOE was $8 million higher and hedging effectiveness cost $5.7 million, while lower G&A partially offset that by $5.9 million.

It is important to note that in looking at EBITDA, the loss in derivative financial instruments includes $5.7 million of hedging effectiveness, which is a noncash item. Now let's look at the detail on a BOE basis.

Revenue in the December quarter was lower, as our price per barrel, excluding NGLs and hedges, dropped to $100.29 compared to $112.64 for the September quarter. The price was negatively affected by turnarounds in the Louisiana refineries that typically use our HLS crude, which are behind us now. So the lower oil price took our total realized price down to $71.54 per BOE.

Looking at the other line items, G&A was lower due to the net change in our share price and the effect that has on noncash stock-based compensation. LOE was higher quarter-on-quarter due to added maintenance costs in addition to some stored costs in October. The bottom line is that EBITDA came in at just over $39 per barrel. Still strong, but clearly lower than what we've earned in previous quarters.

In terms of earnings per share, the big impact for the quarter was the increase in our effective tax rate, which went from 37% to 40%. The increase had an even larger impact on the December quarter, because we also had to true up the accrual from the fiscal first quarter, so that took the apparent rate to about 50%. The rate increase was driven in part by the issuance of the new convertible preferred notes in November. Because they were issued at the corporate level, the interest expense is not deductible for U.S. tax purposes. We do not expect to pay cash taxes this year, as they will continue to be deferred.

Touching base on our share repurchases, to date, we have bought back 243 million of stock in an average price of $25.80 per share. From the beginning of the program, shares outstanding have been reduced about 12%. We've been repurchasing the shares at a cost far below our implied NAV per share on a proved reserve basis. With our expected increase in oil production and EBITDA, our shareholders will benefit from a reduced share count.

Speaking of our NAV, we are providing this new slide so that you can compare our evaluation on an apples-to-apples basis with peers who are issuing their year-end reserves data now. As we've done in the past, all this does is to hold our fiscal year-end reserves flat while running the valuation on the same prices the peers use at calendar year end. You will note that the valuation does not change materially.

Now I'll turn the call back to John to provide additional updates.

John Daniel Schiller

Thanks, West. We have a lot of activity to discuss, so let's begin with the West Delta 73. The horizontal program continues to work, growing oil production in the field and lowering decline rates. During the first quarter -- during the past quarter, we brought on the Hulk and Don Lino wells, drilled a water injector well, and now we're starting to flow the El Diente horizontal well. Total oil production at West Delta 73 today is over 6,000 barrels a day, net; more than triple where it were when we started the horizontal program.

We still have plenty of inventory of drill projects, and the second rig is being mobilized at the fields to accelerate development. There will be some downtime due to rig moves and heavy lifts, but the second rig will give us momentum going into our fiscal fourth year and will hit the ground running for next year.

At West Delta 30, we announced the Stricker discovery. This well was drilling the fault lock that was not previously penetrated. We're in the process of drilling the side track to delineate the discovery. We've set case and have suspended that well for now in order to make some platform modifications. In the meantime, we moved the Ensco 99 rig to the other side of the platform to do a couple recompletions, drill several wells, and then we'll slide it back over to where the Stricker well is to finish that sidetrack.

As we discussed on our Investor Day in October, we have multiple opportunities at West Delta 30. Activity here will pick up substantially with 4 drill wells ready to go in the near term.

At Main Pass 61, the Don Carlos well is another success. It came online with over 1,250 barrels a day oil and it's holding strong at that rate. Activity at Main Pass will continue with 4 additional drill wells and a recompletion the remainder of the year. Now let's look at what to expect in the remainder of this fiscal year and beyond.

As I mentioned, we're expecting some downtime associated with rig moves and facilities work. C platform at West Delta 73 requires modifications before we can put the platform rig on it, so we're running behind on that program. Production for the third quarter will likely be down a little from the December quarter because of platform work, but growth is expected to resume in the fourth quarter. The oil percentage should continue trending up, so we believe we'll end up with solid growth in oil production year-over-year. Increased activity at West Delta 73, West Delta 30 and Main Pass 61 should yield good growth rates with even better growth in EBITDA because of the increasing oil focus.

On that note, with the emerging salt dome play, our joint venture with Fieldwood and Apache at Main Pass is making progress. Fieldwood has joined delineation well on the Heron discovery, targeting the 2 shallow sands that had 79 feet to pay, and the discovery well down-dip. That well should give us data that we need to size and implement a development plan for the fill. The JV has also finished acquiring the wide azimuth seismic data, and it's currently being processed. Soon, the teams will begin using this new data to high-grade previously identified prospects and identify new ones.

Within the ultra-deep, for what Freeport-McMoran now calls the Inboard Lower Tertiary/Cretaceous gas play, the Lomond North well is a discovery. We have 150 feet of net gas pay sands that appear to also have liquids potential. We have begun the completion phase and expect to flow the well later this calendar year.

In addition, the Davy Jones, also, well completion is now progressing smoothly, and it is expected to flow in the next few months. That wraps up our comments, and we can now open the lines for questions, operator.

Question-and-Answer Session

Operator

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

Joseph Bachmann - Howard Weil Incorporated, Research Division

John, just on the ultra-deep program. Can you give us a little more commentary on Lomond North? And what, maybe, has you guys more excited about this one than any of the other wells that you guys drilled so far?

John Daniel Schiller

Yes. I think, Jeb, the key thing there is we just have so much more data. We've been able to core the rock, so we've seen physical evidence and been able to measure the permeability. We know we have good permeability -- it's just like Jim Bob always has talked about, mother nature lays them from the ground bottom up, and we drill them from the top down. And as we've continued to drill the sands, that's where we've seen the sands are getting cleaner. We're also using the 24% to 30% range. So it's more about the quality of the logs and the fact that we supplemented it with core data that we never had on some of the other wells.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay. And then looking for the remainder of this year, so the CapEx went up a little bit. Is that in anticipation of maybe some completion costs associated with Highland or with Lomond North? Or are you guys looking to maybe drill another offset of this well this year?

John Daniel Schiller

You're right on both accounts, Jeb. We have actually got about an incremental $20 million of that increase. The majority of that is for the Lomond completion. Some of that is for the next well. We'll drill in that trend, which is where the unit 201 rig from Lineham Creek's going to eventually move. And then incrementally we decide to keep that Main Pass rig line going through the year, where we've been having good results, that's about an incremental $20 million. And then we've got about $10 million facilities increases.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay. And then last one for me, any update on potential acquisitions?

John Daniel Schiller

Yes, thanks for asking that. I would tell you that we're very close on a couple of things. The stuff overseas has really to the point where we're waiting a government approval. I think that will happen during the month of February. We're also very close on our divestiture of some nonoperated assets. Dollar in, dollar out, those things are going to offset one another. We're going to have more reserves and more production of the result of the overseas still net to the company. So I think you'll see all of that done here in the next 30 to 45 days.

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 a question on the cost side. How should we look at the LOE as we move through the rest of the fiscal year?

John Daniel Schiller

A large piece of that was worked over in maintenance, which was more like $19 million. I think, for the rest of the year, I've worked that number in closer to $15 million. And LOE, I think it was a little bit abnormal quarter and that we had the storm and we had some other things. I would probably tell you that we're up quarter-to-quarter, about $3 million there. I would expect we'd half that number between where we were this quarter and where we've been running.

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

Okay. And then heading into fiscal '15, are there any major facilities upgrades scheduled for next fiscal year?

John Daniel Schiller

Yes. I mean, just so we're on the same page, at West Delta 73, we're putting in a new platform and a drilling platform. And that all-in, including water injection, everything else, it's going to be an $80 million expenditure, not all of which is hitting this year, some will occur in the next year. We're also at West Delta 30 in order to use some of the rigs we want to use. We're having to beef up some of those platforms. And so we're going through and identifying everything, what we can do. We're looking at options of platform rigs versus jackup rigs. I would tell you down the road, we think there's a new platform at West Delta 30, but that's probably 12 months down?

David West Griffin

Yes.

John Daniel Schiller

12 months off before we actually have enough data to support it.

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

Okay. And then last one for me. Just on the international acquisition, can you just kind of walk us through kind of what happens once the deal closes? When would you start drilling and when would you start seeing some incremental production growth in those properties?

John Daniel Schiller

Sure. We're probably looking to close late March, early April, once the government signs off. There'll be a transition period in there where the major continues to operate for up to 6 months. In the middle of that, it would be very similar to what we did when we bought from Exxon from the Gulf of Mexico. We'll start doing some non-rig work. It's not going to be jumped all over it, but at the same time, we can tell you that we put about $20 million into non-rig work and we think there's about 6,000 barrels a day gross uplift. So there's a lot of things we can do there. We've identified of a lot of quick-action stuff. Probably won't actually start that till late summer before we're able to be in a position to do that. But we've already got people on the ground over there today, and we're moving forward pretty quickly.

Operator

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

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Could you update us on your thoughts around moving forward at Vermilion JV and how you guys are looking at that now?

John Daniel Schiller

Yes. I think the big thing there is, clearly, we got to go figure out why the amplitudes were meaningless. There were some people last night that have looked at that too. We're all scratching our heads. So we're going to look at the reprocessing of the seismic. We're going to look at potentially drilling Guinevere, the shallower well and the cheapest well in their drilling agenda in order to get us some data. And it's just too early right now to tell you exactly what the plans are. I can tell you, we're looking at it hard. We're looking at all the possibilities to figure out why these sands aren't showing up, even though there's no evidence to support a false amplitude.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

You said Guinevere would be the cheapest well. Would that also allow you to satisfy the farming commitments or the JV commitments?

John Daniel Schiller

Correct.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay. And what was the cost on that?

John Daniel Schiller

$50 million -- no, not $15 million. For Guinevere?

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

$15 million? For Guinevere.

David West Griffin

$15 million, sorry.

John Daniel Schiller

$15 million.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Okay, okay. And I guess my other question is, historically, you guys have made a lot of acquisitions around sort of the $20 a barrel on a proved basis. Now you guys are sort of trading around that level. As you look at some of your interests right now in going overseas, potentially monetizing a portion of the ultra-deep and balancing that against stock buyback programs, is any of the devaluation on your own stock sort of caused you to rethink some of those ideas and perhaps pile as much as you can into your own shares?

John Daniel Schiller

Yes. I mean -- I think, clearly, we have more liquidity than we've ever had. And so we're going to keep looking at opportunities. I think when you see the actual numbers on the overseas deal, that's still cheapest, by far, in terms of getting in there. I think the -- we'll continue to see where we get on an ultra-deep partnership there. And everything we do is looking at what our capital allocation needs are for drilling wells with really nice returns versus the price of our stock. And I think you've seen our commitment so far. We've put a lot of money into our stock, so I think that's a viable option that we will continue to look at.

David Deckelbaum - KeyBanc Capital Markets Inc., Research Division

Just one more, if I might. Is it fair to say that on the Inboard Lower Tertiary, after Davy Jones 2, would you guys participate in completions that would actually be offshore or would it just be onshore? Or are you non-consenting on the program going forward in the water?

John Daniel Schiller

Now let's get something straight on that. It's complicated. I don't want to drag everybody through it. But here's the way an AFE works in the Gulf of Mexico. You have 120 days from the time that AFEs approved to execute it are deemed null and void, we start the process over. So based on the technical data, Blackbeard West, we're not as comfortable to that to completion or as good of economics as some of the other opportunities we have to put our money to work on. So we're non-consent of it. However, come April 18, if they haven't started that completion, the ball starts all over again. And that's what we think will happen, just because where that platform's going. Right now, to the best of my knowledge, David, the completions that are talking about are Davy Jones. Then they're going to move to Davy Jones 1 and we're going to take that tubular -- those tubules and safety valve to complete Lomond, then I move to Blackbeard West. Right now, I don't know if there's any other completions out there scheduled. And certainly, nothing we've been AFE. So this is a one-time decision only. This is not a common on the program or anything else.

Operator

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

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

Looking at Lomond North versus Davy was, what was the proxy difference there? And I guess, what underpins some of the extra confidence and, I guess, a faster timeline to get that Lomond North completed?

John Daniel Schiller

Well, if you were looking at porosity, it wasn't -- I mean, I think 20 , 24 at Davy Jones; 24 to 30 at Lomond. So a little bit better at Lomond. The big difference, Andrew, comes down to thickness of the sand and the fact that we actually ever get cores and see the permeability. So, if anything, they go the other way on. I would say that our confidence in Lomond North has made us more confident about Davy Jones 2 than where we were pre-Lomond North.

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

Okay. And they're both at about the same pressure downhole?

John Daniel Schiller

Yes. I think similar pressure, similar depths, et cetera.

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

Okay, all right. Great. And the second question I had was, as you look at all, I guess, some of the LOE they put to work there last quarter, what were some of the things that were expended on, on the various platforms? Was it kind of water handling, gas handling? Or was it, I guess -- just give me a flavor for what the -- how much additional capacity you guys were adding to get ready for some of these new wells you're all going to drill.

John Daniel Schiller

A lot of the projects are around the rigs. So, for instance, at West Delta 73, where we haven't moved in the MODUs 150 platform rig yet, we ought to modify the beams to be able to support that weight. And similar things like that, we're getting ready doing a couple of other platforms. The stop over at the Stricker platform has to do with where the pipelines and flow lines are located, and the ability to flow Stricker down the road. So we're going to move the rig to the other side and start working on that. I will also say most of that should be under facilities. Well, I'll tell real world, is when you start a lot of construction activities out there. It's hard sometimes to separate that stuff between facilities capital and LOE. And I do think that's a decent part of our LOE pulse increases just happening more frequently in offshore doing construction work.

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

And I guess, well, given that you're going to get such future benefit from all those expansions, because you may ultimately flow more than just Stricker down there, why would you not look at that in terms of capitalizing some of that?

John Daniel Schiller

Why we not look at what?

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

About capitalizing the [indiscernible]

John Daniel Schiller

Well, that's what I'm telling you, is we're capitalizing everything that's getting caught for the facilities upgrade. So I'm telling you, there's probably some pieces in there that we'll go work harder about backing out. But I'll just tell you from 30 years of watching this, anytime you have a construction activity increase offshore, the LOE tends to go up. It's not as easy on paper to separate those 2. At the day, it's still dollars at our door, it's just we're categorizing it.

Operator

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

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

John, what's your current production level?

John Daniel Schiller

Great question. We're running around 46,000 barrels on good days. The biggest thing we have to deal with right now, during the next 28 days or so, is the demobbing of that rig off West Delta 73 where, as you know from our comments, we're making 6,000 barrels a day. So everyday we're shut in there, it starts affecting us. I would tell you that, I think, as a result of that shut-in time, there's also some on West Delta C where we're moving the other rig. But that platform only makes about 500 barrels a day right now, so it's not as bad. I would tell you that I think if you just focus on oil for the quarter, the load side could be the mid-28. If we do a real good job and some of these wells that we're bringing on, performing -- whether you appear to be performing, we could be very close to flat to where we were this quarter.

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

Okay. As you look at the full year, John, kind of where we are now, how do you feel about the growth targets for the year? Do you still feel comfortable with the 10% to 15% growth this year, or are you thinking it might come in under that?

John Daniel Schiller

Yes. I don't ever remember commenting 15%. I thought we were at 10%. But I think we're somewhere in that 10% neighborhood. It literally is going to come down, Richard, to the downtime. We got -- we're ready for. We've started like, for instance, El Diente. We flow to what, less than 24 hours, guys?

David West Griffin

It's about [indiscernible]

John Daniel Schiller

Got up to about 500 barrels of oil a day. We know we got a good completion there. We shut it in and we're starting a rig down. And so we just -- we got everybody hands on board. We know, if you look across the board, one of the good things this quarter is actual downtime did start improving as a result of some things we've done here in terms of making more effective communication, making sure we coordinate facilities and drilling activities. So that we're doing some construction work, we do it when we're already shut down for the rig and not a separate shutdown. We're starting to see benefits of that in our numbers. We just got to coordinate these couple of big moves. I mean it's -- you got through the economics, it's really great. We moved -- if you remember, we moved West Delta's rig out there 18 months ago. We had about 2,000 barrels a day production. Now we've got over 7,000 barrels a day gross. So when you go take it off, it hurts a little bit more when you put it on. But in between, you're saving $2 million or $3 million a month because of difference in rig cost.

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

Okay. I know it's early at this point, but what are you looking at for CapEx for '15 at this point, including facilities? What do you think would be a reasonable range there?

John Daniel Schiller

Yes. I would tell you that we actually, right now, on our long range current model is going down to be just around $700 million, that's a function of some of the facilities. Dollar is going away. They're in there this year. It's actually more development drilling than what we saw this year. I think plus or minus 5% around that number, $700 million to -- $650 million to $750 million is probably the range when things shake out. Obviously, a couple of things we've been talking about today, where we go forward on ultra-deep, how do those wells come in -- can affect those. Particularly, since you're onshore, you might do a little bit quicker drilling to follow up some of that stuff.

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

Okay. How many rigs are you currently running?

John Daniel Schiller

4.

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

And will that tick up as we move toward the fiscal year?

John Daniel Schiller

So I would say that number is going to stay between 4 and 5. There will be some time when it's 5 and there'll be some time when it's 4. 4 is towards our base number right now.

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

Okay. What's the flow expectations for the Lomond North well?

John Daniel Schiller

You got one to get to go ask [indiscernible]

David West Griffin

They said on their call, 50 million a day and 20 barrels per million of condensate expectations [indiscernible].

John Daniel Schiller

Not so fair enough. Or I would have said 50 myself. So we're good.

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

Okay. And then just lastly, John, what's the near-term subsalt drilling plans with Apache?

John Daniel Schiller

Yes, so we've spudded to offset to Heron. We're looking for those first 2. If you remember, we bought that at salt and had 79 feet oil and 2 sands there. We're going down dip to those wells. Once we confirm the continuity of that reservoir, remember, we had some outstanding perm, outstanding porosity Darcy-type perms. We'll come up with a development plan. And I think Apache's number is about 4.2 million barrels to be commercial, so that's what we're looking for. Anything about 5 million barrels will be commercial. We're probably somewhere around 18 months to first production if we go at a full platform. Would Fieldwood be involved? We'll see it, and may do things a little bit different. I'm not sure yet.

Operator

And our next question comes from the line of Brian Foote from Clarkson.

Brian W. Foote - Clarkson Capital Markets, Research Division

Yes. A question related to the acquisition and the divestiture. Just a clarification, you said that the divestitures are going to close very soon, proximate to the acquisition. And can you just describe the -- you said dollars in, dollars out. I wasn't quite sure what you meant by that.

John Daniel Schiller

Yes. So I mean, the first set of divestitures is a nonoperated piece. We have the buyer there. They're waiting on their board approval. And when you net out the numbers, it's about $110 million to the company, cash in the door. And when you put the door -- put it out the door, it's about $105 million. So it's pretty much washes. And both deals are waiting on board approval, the acquisition and the divestitures. So if we get those done, then we'll have that all done here by the end of March.

Brian W. Foote - Clarkson Capital Markets, Research Division

Okay, great. That's what I suspected. And then in terms of the 46,000 you're producing right now, John, how much of that is oil, how much of that is gas?

John Daniel Schiller

That's run right around 30,000, 30,500 barrels of oil.

Brian W. Foote - Clarkson Capital Markets, Research Division

30,500. And the rig move will improve on West Delta 73. If we're to think about it, you talked about the cost improvements of a rig on a daily basis. But what about the production improvements there? So if you're making 6 right now, is there any production enhancement just through the rig move?

John Daniel Schiller

Due to the rig move, the way I would caution is this way, Brian, we're going to go out there. And remember, we're going to run a wireline program, a production logging program at all the horizontal wells we drilled. We've only been in one of them because of the rig being on top of all those wellbores. And yes, our expectation is there's 500, to 1,000 barrels of upload to be gained from these wells once we figure out where is the production coming from, where is the water coming from. We're prepared to do some things to isolate water depending on where it is in the wellbore. And all of those things should be helpful to production, but we just haven't been able to do that with the rig out there. So that program will probably start early March.

Operator

And our next question comes from the line of Steve Berman from Canaccord Genuity.

Stephen F. Berman - Canaccord Genuity, Research Division

Your press release, the Pi well, I don't think I heard you talk about it. Could you maybe elaborate a little on that. And remind us, is that a horizontal well or not?

John Daniel Schiller

Oh, Pi. Pi, we actually -- remember the well we drilled over a year ago out of Grand Isle and we have stack pays in it. The initial completion ended up being a gas end, that blew down. So we went out there and we completed it. We have 2 more, the hind pipe zones now. And we're making 1,000 barrels of oil a day out of that wells, so we're pretty happy with it.

Stephen F. Berman - Canaccord Genuity, Research Division

And is that a horizontal or not? I don't remember.

John Daniel Schiller

I'm sorry, it was vertical completion.

Stephen F. Berman - Canaccord Genuity, Research Division

Vertical, okay. And any plans at Grand Isle beyond Pi in the foreseeable future?

John Daniel Schiller

Yes. I would tell you that's one of the things we're looking at right now is how to allocate resources around some of those assets. I think the teams on Grand Isle and South Tim 21 and South Tim 54 have been going through their inventory. And I think you'll see us move some things around and start getting some of that drilling going. When we talk about a fifth rig, that's where it's destined for, is to drill the Grand Isle South Tim area.

Stephen F. Berman - Canaccord Genuity, Research Division

And if I recall, you are looking close at these areas in terms of a horizontal potential. Any updates there?

John Daniel Schiller

Nothing specific, Steve. I'd just say that, yes, we're doing that. As I said, when you move a rig out of a team's area, it gives them a lot more time to work those tight things and identify it, and then trying to capture capital against the other opportunities we have.

Stephen F. Berman - Canaccord Genuity, Research Division

Okay. And one more. You're pretty much -- at your $250 million buyback authorization, any thoughts on going back and expanding on that?

John Daniel Schiller

Yes. I would be careful how you word that. We actually authorized $250 million before we did the convert. So that purchase on the convert is sort of away from that. So we still have some room. We have to operate $150 million in the room.

Operator

And our next question comes from the line of Chris McDougall from Westlake.

William Christopher McDougall - Westlake Securities LLC, Research Division

I'd like to get a sense of your operations overseas and kind of your plan going forward with the acquisition. How many folks are you going to have over there? Just give us a little bit of color there.

John Daniel Schiller

Chris, let me just start by saying this. I promise, when we get these bills closed, we will have a conference call and we'll give you a lot more detail about why we're excited about it. We'll get you to understand the way the production sharing contract works, and it's a fixed production sharing contract. But I will just loosely tell you that we're talking 3 or 4 ex-pats from here over there. Most of it will be run-in-house with experienced country managers who have already done this type of stuff. It's -- the property we're talking about is 5% of this particular major asset, and it's the first divestiture they've done over there. So we think that we've jumped from trying to come into the Gulf of Mexico late, although we got lucky getting the Exxon deal. Everything else we've got had gone through another independent before we got it. So now, we're the first guy in getting some of these assets, and there's going to be a lot of low-hanging fruit. That's just the nature of that beast. So we'll give you a lot of run-down on that, but that's sort of the ballpark in terms of people. I will also tell you that, as envisioned today, as the work plans we've put forward, these properties self-fund our CapEx. So we're not talking about any cash flow drain on the assets in the Gulf.

William Christopher McDougall - Westlake Securities LLC, Research Division

Okay, great. On the tax rate Southwest, do we -- we've got a very little cash tax rate. With the current spending plan, how many years out do you see the cash tax rate being 5% or below?

David West Griffin

Right. Yes, that's a great question. Right now, we're not envisioning being a cash taxpayer over the next year or so. What was really driving the cash taxes that we were paying was we actually had to pay some withholding taxes on distributing money out of to Bermuda so that we could pay our dividends on our common and our preferred. With the 3% convertible bond issue that we did this fall, that gives us enough cash at the Bermuda level. We don't need to do that. And so we're not going to be paying any withholding taxes. So the bottom line is, cash taxes, we're not envisioning any for quite some time.

John Daniel Schiller

That's one of the beauties of the overseas acquisition. That cash will flow straight to Bermuda, too and not be subjected to any other taxes.

William Christopher McDougall - Westlake Securities LLC, Research Division

Okay. That's interesting color. John, getting back to the -- on the operations side, we've seen great growth out of West Delta 73 and some strong production growth, but overall, oil production is effectively flat. But where are we seeing the declines? How much of it is these facilities and down time associated versus just the natural declines? And will we see the natural decline rate on either increase or decrease going forward?

John Daniel Schiller

I think you're going to see the decline rate start getting smaller than it is. If you look at our wells, they've been on more than 3 years. They're at about a 14% decline rate. So as the horizontal wells go on 3 years, that's going to be less decline, which is flatter. I will tell you that the areas we fight production is sometimes Main Pass, where we have some regular wells, but we need more water injection. And so as we start to clean those reservoirs, the rates fall away from us and then level off, but that's sort of a large instantaneous. So you go from 1,500 barrels of oil a day to 500 barrels a day. And then shortly it will slowly begin to decline from there. That's one of the things we're dealing with right now, the well that we need to get water. One of the wells we just drilled at Main Pass, they've indicated that we're getting ready to drill rather, is possibly going to be a producer or injector depending on what we see. We know we need water in the reservoir, but we're not sure that we still won't be in the oil column when we initially get there. We've got a couple wells framed like that in the Main Pass area. So -- but that's an area where the production has been as high as 14,000, down from about 10,000 or 11,000. The other area was obviously Main Pass 72, where we really had some successful ramp-up spring of '12 with the Onyx and program and those rig completions that we're making 9,000 barrels of oil a day, and we just sucked that 2 million barrels out of the ground. And those same wells today make about 2,000 barrels of oil a day. So what you need is another nice one of those to get you up quick. But that's kind of where we fight it at South Tims. 21 is sort of ahead of budget. 54 is ahead of budget. So there's no dramatic falloffs at any place that are surprising us.

David West Griffin

And to be -- we've got to be clear on that, oil volumes have been growing the first half of the fiscal year with only 2 development rigs running. So once we get these other rigs on and drilling, you'll see that ramp.

John Daniel Schiller

And that's the biggest part of it is a matter of development wells we're drilling and the fact that every well we drill is not necessarily development well. Some of them have been water injector.

Operator

And our next question comes from the line of Adam Michael from Miller Tabak.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

I think most of my questions have been answered, but if we could can go back to that Stricker well and maybe discuss a little bit of expectations as far as the timing of when you think you'll get that well on, and then maybe expectations on flow rate and how many development wells you think you need there?

John Daniel Schiller

Yes, Adam. I would tell you on the Stricker, remember, we've picked up the Ocean King to drill that. Because of the side track and some other issues, it's lasted longer than we thought it would. And so what's happened is we drilled back sidetrack. We've put in an immediate casing where we're seeing some pressure again from being close to the salt. My thoughts there is there's probably going to be 2 sands that will take the completion in. I think 1,000 sort of barrels a day is the right number because of how shallow these sands are. Maybe it can be a little higher, but that's a good number to put in there. And so we're going to move the Ocean King out of here. Give it all for payroll. Move in the Ensco 99 that we have a long-term contract on. And because of some facility things that we needed to do, it makes more sense to start on the other end of the platform, do a couple of 1-week completion or 2, Tom? 1-week completion, and then drill a couple of wells while we're in that end of the platform, then we'll come back to Stricker and get it finished. But it's all about just most efficient use of our capital and not spending money stupidly.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Okay. And then -- and the realized oil pricing, can I get your thoughts on kind of the HLS market differentials going forward? And what are you guys doing on the hedging front to kind of match up what oil production you used in WTI or Brent futures or -- what's your thoughts there?

John Daniel Schiller

That part is easier. We're using WTI. We've put some stuff in place in February to take advantage when the price ran up there and kind of lock-in that differential. The differentials themselves, when I stood up at a conference or a dinner during May, because I really don't have a clue anymore. Some of the things we're getting free on that, it zones the other way. I think we will maintain a premium on the WTI. I don't see that collapsing. Whether we stay above or below Brent, timing is looking good a lot, and details of the sands are up in the air right now.

David West Griffin

Yes, I mean, I think there are so many different opinions out there in the marketplace. It's hard to say. Like John said, we do expect HLS to continue to give a premium to WTI, but it's been, obviously, very volatile, and we'll continue to use WTI as our hedge choice.

Adam R. Michael - Miller Tabak + Co., LLC, Research Division

Okay. And then last question, I saw you guys put the updated PV-10 with the latest crude numbers as of 12/31. Do you guys have a PDP number? Because I have to think you're trading pretty close to PDP, PV-10, and I'm curious what that number might be.

John Daniel Schiller

Yes, we do have it, but I don't know that we have it in here.

David West Griffin

I can get it, John.

John Daniel Schiller

We'll get it and get it out there.

Operator

Our next question comes from the line of Joe Magner from Macquarie.

Joseph Patrick Magner - Macquarie Research

I just wanted to go back to the growth outlook for the year. The 10% was, I think, an attempt to account for more active program and some of the downtime expected, given some of the rig moves anticipated. And I'm just kind of curious, the current activity level, is it above or below or in line with what had been initially anticipated?

John Daniel Schiller

It's a little bit below in that we didn't pick up the second rig at West Delta as soon as we thought. So that delay is going to hurt us a little bit. That would be the biggest impact area, Joe. Obviously, West Delta 73, that drilling has gone pretty much the way we thought. The drilling in Main Pass has gone the way we thought. We're shutting there right now. They've got to do some repair work. It's taking about 3 weeks off that rig, but we had that scheduled. So that's kind of it in a nutshell. We'll be a little bit behind so we've got to make it out with better wells or better base production. And right now, as Stewart pointed out, with the 2 rigs, we've been holding our own pretty good.

Joseph Patrick Magner - Macquarie Research

Okay. And then one other, I guess, program you talked about was the production logging at West Delta 73. Is that something that has been accounted for? Or if not, what's the extent of that program? How long might that affect the volumes out of that platform?

John Daniel Schiller

Well, most of that will be actual run well where the wells are flowing, so it's not going to have much of a volume impact, and then we'll be working around a rig demobe. The volume impact there should be positive. If you remember, we actually skipped the rig to the side and paid for it for a couple of days on Big Sky 2. As a matter of fact, the first well we drilled, it came in at 3,000 barrels oil a day, and all of a sudden, the water hit us. And when we went in there and logged it, what we found out was water was coming all the way out of the tunnel the last 200 feet of 1,000-foot lateral. So it's really -- we don't think it will be affecting our recovery much. But if you go back in there and find that same thing out, you'd probably sort of plugged in at the bottom, and hopefully, you'll find out that you increased your oil track mood to more volumes, eliminating the water. So that's the only time we've been in any of those wellbores. So those are the things we're looking for. Remember, the GOM well is making 300, 350 barrels of oil and a lot of water, 2,500 barrels of water. So again, like Big Sky, we would have told you pre-going in there that we thought that water was near the hill of the well, right there at the start, and maybe it is. If it is, we'll look to eliminate it. But those are the common things we're looking for. Minimum effect on downtimes, because you're not doing a lot of heavy lifts. Once you're up there, you're just putting up the lubricator and go on.

Joseph Patrick Magner - Macquarie Research

Any thoughts on how long those -- if you're able to identify some of the areas of water production is coming from, how long would it take to go in and set a plug or isolate it? Is that a quick process or...

John Daniel Schiller

My production guys are ready to go on that, and we've got everything we need. So over the course of the month of March, I think you'll see most of that work done.

And Adam, updating you, I think what you really wanted was the PDP's pre-developed production. That number is about $3.5 billion on the new number.

Operator

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

I was hoping to look at what's this year's percentage of CapEx that's really development CapEx versus exploration in facilities? And how's that going to compare, as we move into next year, in that preliminary $650 million to $750 million number that you gave, John?

John Daniel Schiller

Yes, hold on one second. I'll get it for you. It's -- I will tell you it's going up. We go from drilling 15 wells, not counting water injectors, to drilling 22 wells next year, along the lines of the numbers that I'm telling I'm talking about. So we'll get a lot more development wells done. And then we are currently...

David West Griffin

At 50% for both of the drills.

John Daniel Schiller

For an issue?

David West Griffin

Yes.

John Daniel Schiller

Yes, so we issued about 50% of that money to get into development drilling. Mike, you hit on the right point there.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Well, it's good. I'm at least on the right track there. In terms of -- take that one step further with adding the third development rig here, and it's impressive what you've done at West Delta 73 on ramping that oil program, when do we see that really kick in? And maybe if you could just talk about this -- the confidence of if you have a visibility of just sequential gains in the oil production as we go from maybe now through fiscal '15? When do we really start to see that ramp as it pertains to total company production?

John Daniel Schiller

Look, 7, 8 -- I'm counting for you, 9, 10 -- I'm counting 12. So between now and the end of this calendar year, you have 12 wells down the horizontals. So we drilled more wells over the next 10 months than we drilled today in the fields. So obviously, you start expecting to see things more dramatic than what we've seen so far.

Michael Kelly - Global Hunter Securities, LLC, Research Division

And in terms of quantifying that, we're thinking are you there yet? Where we could look at 1,000-barrel-a-day upticks every quarter? What's -- what's kind of -- how do we look at this in terms of that stair [ph] stuff?

John Daniel Schiller

Several thousands by the fourth quarter. 1,000 to 1,500 a quarter is probably not a bad number.

Operator

Our next question comes from the line of John Polcari from Mutual of America.

John Polcari

A couple of questions. The size of the acquisition, you said that -- did I get it right at $105 million?

John Daniel Schiller

Correct.

John Polcari

So even if it's awash with monetizing some of your assets, I'm looking at the value of PDPs, did you just mention $3.5 billion?

John Daniel Schiller

Right.

John Polcari

So you're currently almost 15% discount to the PDP valuation, where we are now. Stocks off 40% from as recently as October. Cash to date, above the current price with the average repurchase price of $25.80. That's $45 million left on the table. And I know you can't predict where the market's going, but that only leads up to the question why not take the $100 million that you're monetizing and buy back another 7% or 8% of the stock? How exciting can it be in the overall size of the company to step outside of the U.S., outside of the Gulf for what is, you seem to have indicated, a relatively modest venture, when your -- you appear to be trading at a dramatic discount here domestically and another $100 million of purchases where you have another $100 million left in authorization because of the convert? $100 million monetization would -- you could be buying in another 10% of the stock at -- unless you're going to take it private at some point, buying into the stock would have to put a bottom in on the price. Can you just speak to that? Because I don't -- I know it's about allocating capital. I just don't understand that these valuations, what the attraction is where you're headed.

John Daniel Schiller

Yes, 2 things. I think I told you already. We're going to look at that [indiscernible]

Joseph D. Gibney - Capital One Securities, Inc., Research Division

Maybe you could just tell me again.

John Daniel Schiller

We agree with all your numbers. I'm not disagreeing with them at all. I will tell you that we also get paid to make sure that somebody's heading in the direction that it needs to be headed long-term. And then the first over there, when they start turning loose these brown fields, it's going to give us some tremendous capital opportunity, which is why when we get these deals done, we'll have a conference and walk you through why we're excited about it. And I think, yes, we all agree. We're going to keep looking at where we trade and how cheap we are and what's the right solution to get our stock price up. Certainly, we've got more investment in this company than just about any other employee group. So I promise you, we're not looking to take the price down.

John Polcari

Okay. You've covered it already, but could you just quickly recap the -- since the McMoRan sale, there's been less of a focus on updating on the ultra-deep prospects. And you had mentioned Blackbeard West, could you just recap that again?

John Daniel Schiller

I mean, here's what's going on out there. We're completing Davy Jones 2. That completion is going along very nicely...

John Polcari

And that's first -- that's this quarter, correct?

John Daniel Schiller

No, that's some time first half of the year. And then from there, we're going to yank the pipe out of Davy Jones 1 and take it over to Lomond well, where we've already started that completion. We're going to drilling liner. Next, we'll be running production casing and getting that wellbore ready to bring on production in a similar time span, some time early this summer. After they've moved the rig to Davy Jones 1, they're going to take it to Blackbeard West to do a completion there.

John Polcari

Which would be end of year?

John Daniel Schiller

Probably in the summer. And then the rig that we drilled, that Chevron drill, the Lineham Creek well is going to start demobbing, and we'll move up north to the next prospect, and that's probably a sort of June timeframe on spudding that well.

John Polcari

And we're where is Blackbeard East these days?

John Daniel Schiller

Still there. I just don't know -- STX [indiscernible] They control the rig. I'm talking...

John Polcari

I'm sorry, I can't hear you. You're breaking up.

John Daniel Schiller

I said it's still there. STX controls the rig. So I'm telling you there's as much time just as I know that it adds up today, which is taking you through the majority of this year.

John Polcari

So they're still on the -- they still have a rig on it?

John Daniel Schiller

No, Blackbeard East is suspended. No rig on them.

John Polcari

And you don't know what the exact plans are right now for the balance of the year on that?

John Daniel Schiller

Correct.

John Polcari

Okay. And can you speak to -- in the press release, you folks put a hedging ineffectiveness. How ineffective was the hedging? Can you just -- can you give us a little more color on your hedging ineffectiveness? Can you expound on that?

John Daniel Schiller

Yes. I mean, like, in the simplest form, it's a mark-to-market on what the strip is worth today versus what you had it at. You get that.

David West Griffin

It's noncash, and it's still -- the chances of it ever becoming a hit in the income statement are almost 0. It's the way the government has you do the accounting...

John Polcari

No, I understand the accounting. I just -- I mean, I have yet to see somebody call it hedging ineffectiveness. I just wondered if you would...

David West Griffin

I just figured it as widely used throughout the industry and throughout not just this industry, all industries, as it applies to derivatives. So...

John Polcari

Well, I mean I haven't seen it in the press release on the other 22 companies that I've looked at, but go ahead.

David West Griffin

Well, I mean, maybe it's just that they do not address it, but we did because $5 million, and if it's unexpected, we have it go the other way, too. I mean it goes the other way often as well. So it's related to the perfect hedge that you establish when you set up your program and how your hedges reflect the movement in your perfect hedge. So it's a very technical accounting thing and I wouldn't worry about it a whole lot. We're just trying to explain where the variance came from.

Operator

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

Joan E. Lappin - Gramercy Capital Management Corp.

I guess the number of my question -- this is sort of silly, but why on earth after years and years of the ultra-deep that we've got a new name? And whose idea was that?

John Daniel Schiller

I'm still calling it ultra-deep. Don't worry.

Joan E. Lappin - Gramercy Capital Management Corp.

Good, good. We're with you. Okay, so essentially, if you're taking out all the goodies from Davy 1, then that's just been declared a -- and we're not bothering anymore, and we'd like to recover all the money we put down the hole that we can. Is that correct?

John Daniel Schiller

Yes, I think the way that status is going to work is to temporary abandon. From our accounting standpoint, we have pulled the numbers in to our DDNA [ph] number this quarter along with Blackbeard.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay, now can we revert to the monetization of the ultra-deep? Originally, you had said, "Well, if they bring in a partner and were asked to go along, we will." But now you're talking about we have -- we're not thrilled about spending money on Blackbeard West, or we can get better ROEs elsewhere or whatever. So could you kind of clue us in to what your real thinking is on ultra-deep at this point?

John Daniel Schiller

Yes, I mean, Joan, look. I think we're pretty straightforward all the time. We've got a lot more data on the newer wells. We've gotten course. There are a lot of things to give you a lot of confidence in their ability to flow. When you go back over to Blackbeard West, we -- all we have is open-hole logs, and there's a couple of different ways to look at those open-hole logs in terms of how they've been processed and there's analogies to support what Jim Bob's doing. He's got some great examples that say that the rig distribution we're seeing there could be pay it could be liquid pay. My guys don't necessarily agree. So I mean, it that happens all the time. We're not on the same page. It's the same data. But the risk reward where I sit today for our company is to take that money and go drill a horizontal well versus putting more money into that particular well. I mean, it can't get any worse than that.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay, then how would you go about -- I mean, what would be the process of monetization of your interest there in the ultra-deep partnership that's been ongoing now for a long time?

John Daniel Schiller

Well, I think from our view, we're not getting out of the bill. What we're looking for is to get someone to come in who wants to take a piece of the action and help us pay some of the bills going forward.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. So the prospects for that have to be a lot better with that gas closer to 5 than when a couple of years ago, it was closer to 2?

John Daniel Schiller

Yes. And I think it tells better of your LNG exporting. The guys were talking about wanting access to gas, so all of those things help.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. Okay. And I know you answered about the authorization. Okay, so are there any particular issues and any ones accepting -- I guess I have 2 more questions. Any issues expected on completing Davy 2?

John Daniel Schiller

Running smoothly right now. So I'd -- it's a much bigger wellbore on a relative basis. We haven't gotten any hiccups at all. Knock on wood. So I think everything's going to go as planned.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. And then in terms of -- well, I guess somebody asked earlier, but is the expectation there'll be more on-shore than off-shore work in the trend?

John Daniel Schiller

Yes. I mean, I think that probably one of the reasons you heard it renamed, as we go on-shore, you start getting these targets at depths less than 25,000 feet. So it's more like the deep gas that Jim Bob did at Flatrock. So yes, I think in the environment we're in, I think you're going to see more drilling on-shore then off-shore. And you're going to see us staying close to where things are working.

Joan E. Lappin - Gramercy Capital Management Corp.

All right. That's a good thing. And then the last question is then with Lomond. Again, we're going now for shallower sands, same reasons that you've just described?

John Daniel Schiller

No. That was actually more about the Lineham Creek. If you remember the regular sands at Lineham Creek are sort of in the 24,000, 25,000-foot depth. And as you go further towards the shores, we think it'll be shallower. At Lomond, our pay sands are at 28,500 to down to below 29,000.

Joan E. Lappin - Gramercy Capital Management Corp.

Okay. And I guess my last question is when do you think you're going to get your quarterly production over 50?

John Daniel Schiller

Hopefully sooner rather than later. I would say that I think if we get through this quarter with a downtime, that we've got a good chance to getting that right after that.

Operator

Our next question is a follow-up from the line of Andrew Coleman from Raymond James.

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

Last question I had is your order of purchase interest from Black Elk, I know it's a small property, but is there any status update on those?

John Daniel Schiller

Andrew, we're targeting about 500 barrels a day of production out of there starting around April 1. We had a meeting with the BSW this week and went through everything and they've signed off that -- all the restrictions they had on Black Elk were lifted, and we'll be operating this Energy XXI once it's in our name, and I think that it will along smoothly and you'll see some nice production gains there.

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

Okay. And then, I guess, if you were to look at gaining any more data collection seismic or what not, that's probably a fiscal '15 kind of issue?

John Daniel Schiller

Yes, actually, I think we're in pretty good shape one seismic data. They've just continue to remap that field. We identified some opportunity early there. It fits better with our whole synergy of operations in terms of gas supply and some of the things it needs. So it's kind of a win-win. They needed some cash and they fit into our system better.

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

Okay. And you think there are many additional tuck-ins like that cross your asset base here? Or was that not one of the major ones out there?

John Daniel Schiller

Yes, there's a few more left in that area, and it's probably not going to happen in the next 3 months, but I think over the next course of the year, there's a still a few deals to tuck in around the main area there.

Operator

And our final question for today is another follow-up coming from the line of Chris McDougall from Westlake.

William Christopher McDougall - Westlake Securities LLC, Research Division

On your reserve report, I'd love to get a sense of what sort of production growth is on -- is into that reserve report for the kind of out-years? I mean, clearly, there's some. Is it the kind of 10%, 15% year-on-year number or what?

John Daniel Schiller

It's the stuff we showed at Investor Day in October. It's a sort of 10% to 15% growth. When we talk about those numbers, we're not really putting any exploration in there. We're talking about majority 2P reserve-type stuff. So you're drilling crude under those locations. We're sliding a few sleeves that we have a left to slide, and then the probables.

William Christopher McDougall - Westlake Securities LLC, Research Division

Okay. And West, just a question from that hedging effectiveness. I think about that as just the disconnect between your selling price and then Brent and WTI, and this is kind of the first quarter that we've seen such a big disconnect, and so that's why we haven't seen that type of stuff before. Is that a fair understanding?

David West Griffin

Yes. Yes, that's correct.

William Christopher McDougall - Westlake Securities LLC, Research Division

Great. And can you just remind me how much you have available on the revolver? Not that you need it.

John Daniel Schiller

Sure.

David West Griffin

Yes, that's right. I mean, John mentioned our total liquidity. We have about $710 million available under the revolver. Then we have about an additional $356 million of cash. So it's a little over $1 billion, between $1 billion and $1.5 billion.

John Daniel Schiller

Thanks, everybody, for joining us. We appreciate it, and we look forward to getting back to you before the next quarter with some updates on the acquisition divestiture front.

David West Griffin

Thanks.

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.

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