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Plains Exploration & Production (NYSE:PXP)

Q2 2012 Earnings Call

August 02, 2012 9:00 am ET

Executives

Scott D. Winters - Former Vice President of Corporate Communications

James C. Flores - Chairman, Chief Executive Officer and President

Doss R. Bourgeois - Executive Vice President of Exploration & Production

Analysts

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

David W. Kistler - Simmons & Company International, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

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

Operator

Good morning. My name is Jody, and I will be your conference operator today. At this time, I would like to welcome everyone to the Plains Exploration 2012 Second Quarter Earnings Results Conference Call. [Operator Instructions] Thank you. I would now like to turn the conference over to Mr. Scott Winters, Vice President of Corporate Planning and Research. Please go ahead, sir.

Scott D. Winters

Jody, thank you. Good morning, everyone, and welcome to our conference call. Earlier this morning, we issued our earnings release and filed our 10-Q.

Our conference call today is being broadcast live on the Internet, and anyone may listen to the call by accessing our company website at pxp.com. The webcast, the 10-Q and today's press release are all available on the website in the investor information section.

Before we begin today's comments, I'd like to remind everyone that during this call, there will be forward-looking statements as defined by the SEC. These statements are based on our current expectations and projections about future events, and involve certain assumptions, known as well as unknown risks, uncertainties and other factors that could cause our actual results to differ materially. Please refer to our filings with the SEC, including our Form 10-K for a discussion of these risks.

In our press release and our prepared comments this morning, we present non-GAAP measures. A reconciliation of non-GAAP financial measures to comparable GAAP financial measures is included with the press release. Please take a minute to review the reconciliations.

On the call today is Jim Flores, our Chairman, President and Chief Executive Officer; Doss Bourgeois, Executive Vice President of Exploration and Production; Winston Talbert, Executive Vice President and Chief Financial Officer; John Wombwell, Executive Vice President and General Counsel; and Hance Myers, Vice President, Corporate Information Director.

For the 3 months ended June 30, 2012, PXP reported net income attributable to common stockholders of $223.2 million or $1.70 per diluted share compared to net income of $124.9 million or $0.87 per diluted share for the 3 months ended June 30, 2011.

Second quarter net income includes certain items affecting the comparability of operating results. Those items consist of realized and unrealized gains and losses in our mark-to-market derivative contracts and unrealized gain on investment in McMoRan Exploration common stock and other items. When considering these items, PXP reports net income attributable to common shareholders of $45.8 million or $0.35 per diluted share compared to $77.1 million or $0.54 per diluted share in the second quarter of 2011. The 2012 results include an increase in the oil and gas depreciation, depletion and amortization rates which resulted in a $0.24 after-tax decrease in earnings per diluted share. The higher DD&A rate reflects the impact of lower sustained natural gas prices which caused reductions in the value of undeveloped locations in the Haynesville Shale and increased transfers from the unproved property pool to the full cost pool.

Some quarterly highlights comparing second quarter 2012 to second quarter 2011 results include: oil and gas liquids revenues increased 30%; daily sales volumes per diluted share increased 10%, or 36% pro forma for the December 2011 asset sales; oil and gas liquids -- I'm sorry, oil and liquids daily sales volumes per diluted share increased 34% or 53% pro forma for the diluted -- for the December 2011 asset sales; operating cash flow increased 16%; cash margin per BOE increased 23%. The standard measure of discounted future net cash flows was $6 billion and PV-10 value was $8.9 billion at June 30, 2012, compared to $5.1 billion and $7.9 billion at December 31, 2011, respectively.

Operating cash flow, cash margin for BOE and PV-10 are non-GAAP measures.

Oil/liquids revenues increased $120.2 million to $519.5 million for 2012 from $399.3 million for 2011, reflecting higher sales volumes and higher average realized prices. Oil/liquids sales volumes increased 11,300 barrels per day to 59,800 barrels per day in 2012 from 48,500 barrels per day in 2011, primarily reflecting increased production from our Eagle Ford Shale property, partially offset by a production decrease due to the divestment of our Panhandle properties in December of 2011.

Excluding the impact of our divestments, sales volumes increased 17,200 barrels per day in 2012. Our average realized price for oil/liquids increased $5.08 per barrel to $95.50 per barrel for 2012 from $90.42 per barrel for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012, for our California crude oil production that replaced the percent of NYMEX index pricing with market-based pricing approach. The average ICE Brent index price for 2012 is $108.73 per barrel compared to the average NYMEX index price of $102.34 per barrel in 2011.

Gas revenues decreased $67.7 million to $46 million in 2012 from $113.7 million in 2011, primarily reflecting lower average realized prices and lower sales volumes. Our average realized price for gas was $2.18 per Mcf in 2012 compared to $4.23 per Mcf in 2011. Gas sales volumes decreased 64 million cubic feet per day to 231.3 million cubic feet per day in 2012 from 295.3 million cubic feet per day in 2011, primarily reflecting our Panhandle and South Texas properties divestment in 2011, December of 2011, partially offset by increased production from our Eagle Ford Shale properties.

Excluding the impact of our divestments, sales volumes increased 17.8 million cubic feet per day in 2012.

Lease operating expenses increased $5.6 million to $87.7 million in 2012 from $82.1 million in 2011, reflecting increased production primarily at our Eagle Ford Shale property and repairs and maintenance primarily at our California property, partially offset by our Panhandle and South Texas properties divested in December of 2011.

Steam gas costs decreased $7.2 million to $9.7 million in 2012, from $16.9 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 4 Bcf of natural gas at a cost of $2.41 per MMbtu compared to 4.1 Bcf at a cost of approximately $4.13 per MMbtu in 2011.

Production and ad valorem taxes increased $2.2 million to $19.1 million in 2012 from $16.9 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our December 2011 asset sales.

Gathering and transportation expense increased $2.2 million to $19 million in 2012, from $16.8 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties, partially offset by our December 2011 asset sales.

Interest expense increased $15.8 million to $53 million in 2012 from $37.2 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding, partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization, but in the process of development. We capitalized $15.2 million and $33.5 million of interest in 2012 and 2011, respectively.

The derivative measurements we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are mark-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement. PXP recognized the $221.8 million gain related to mark-to-market group derivative contracts in the second quarter of 2012, which was primarily associated with an increase in the value of our crude oil derivative contracts due to decreased forward prices. In the second quarter of 2011, we recognized an $18.9 million gain related to mark-to-market derivative contracts.

At June 30, 2012, we owned 51 million shares of McMoRan common stock. PXP is elected to measure its equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as a gain on investments measured at fair value in our income statement. PXP recognized an $86.8 million unrealized gain in the second quarter of 2012 related to our McMoRan investment, which is primarily associated with an increase in McMoRan stock price. For the second quarter of 2011, we recognized a $43.3 million gain related to our investment.

For the second quarter of 2012, PXP had cash expenditures of $423 million for additions to oil and gas properties and $3.6 million for leasehold acquisitions. Of the $426.6 million total, approximately $43.6 million was funded by Plains Offshore Operations Inc., PXP's consolidated subsidiary.

And finally, PXP updated its 2012 full year operating and financial guidance to reflect higher sales volumes; higher oil volumes, as a percentage of total volume; updated oil price realization; and higher DD&A expense for BOE. The 2012 operating financial guidance is included with the financial tables at the end of this release. With that, I'll turn the call over to Jim.

James C. Flores

Thanks, Scott. Good morning, everyone. We are delighted to deliver these results in the second quarter and look forward to the second half of 2012 and beyond, because PXP is in a great position with its oil base, an oil growth story, driving revenues and oil margins on the pricing side and also on the buying side across our Eagle Ford assets and also our California assets, with the Gulf of Mexico coming along in 2014. So we continue to be conservative in our outlook as far as gas prices and gas business. We also are very constructive on oil prices going forward due to the tightness in the market and the world demand [indiscernible] 91 million barrels, and [indiscernible] see it on the paper at a $104, $105 Brent that works very well in our model. And you can see where the Eagle Ford is becoming much more efficient. We're getting wells on faster. There's a lot of ample services, both on frac-ing and water and all the concerns that everybody had a year ago. We're hearing about, because of the wide geographic nature of the Eagle Ford play, we're actually the beneficiary of those. One thing it's causing us to do is get wells on faster, completed quicker, cheaper and that type of thing. And therefore, we're -- really accelerated the efficiencies of our business. We're looking forward to the second half of the year when the volume increases and the revenues from that will drive our CapEx budget and also our stock buyback towards the second half of this year. I'm not going to belabor a lot of comments. We have everyone here. We'll open it up for questions, operator, and get on with what's on your mind.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Brian Lively from Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Looking at the Eagle Ford volumes in Q2 versus April, just want to get a sense of how production is trending currently. And maybe if you could provide like the June exit rate, that would be helpful.

James C. Flores

Well, Brian, just look at the rig count. We brought an 8 rigs, all during the second quarter. We're going to run 8 rigs the rest of the year. We may even drop a rig just due to efficiencies. Our drill time has been cut so much, and we're contemplating our 2013 CapEx plan being with 1 less rig and still drilling more wells than what we have planned in our base plan just because of the rig date time has become so efficient. Also on the frac cost and the frac availability, we're frac-ing a lot more wells and putting a lot more wells on completion due to equipment availability that we didn't forecast a year, 18 months ago. So we're kind of working through those efficiencies and we are thinking from the standpoint of where we are production-wise. The big variable -- so still that's a big variable second half of the year. How many rigs does EOG run in the joint venture area? We've heard as many as 6, but there's just 2 in there right now. So that's one of the variables we're working off of. So it's difficult to give you a ramp up. I think you just stay within guidance going forward and figure that out. We'll give you kind of the certain answer dealing with all the uncertainties that we deal with above that.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's a good color. Then on maybe the same question then, talking about the lower rigs, lower frac cost. Where do you guys sense or hope, I would say, where the CapEx would trend on a per well basis?

James C. Flores

I don't think the CapEx on a per well basis will go down that much, because we're drilling longer laterals and putting more frac stages just because we're able to achieve much more production volumes out of these better-designed wells. I'm not saying larger designed, but they're just better designed, and as our engineers tweak them, we'll give them flexibility. So I think once the amortization of the facilities cost come out early next year, I think actually you'll see a big drop. Like we're looking between $7.8 million and $8.2 million is the long-term cost of our wells out there, and we're about $1 million, $1.5 million above that right now with the facility cost amortization.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, got it. On the Haynesville, looking at the slight uptick quarter-over-quarter, is there any way that you could isolate between how much of that was constrained production coming back online versus what the underlying base would have been?

James C. Flores

I think you take the first quarter off of the second quarter, and then you get that -- you might get the -- we're fairly flat, but you got to figure out a decline in the first quarter, you can figure out how much of that was coming back on from curtailment.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. But you don't have an estimate of what the curtailment, the uncurtailed, curtailed volumes were for the second quarter?

James C. Flores

Brian, I tell you what, I really don't focus on our gas business that much. I don't -- in that respect. I can get that -- we can get that for you. But I can tell you what's happened in the Eagle Ford and California. I'm being facetious. You know what I'm talking about. But I'm just -- the gas business, the curtailments we did, we're not big on curtailments. We're not big on coming back. I mean people are managing their business. So our gas business being in a box. We're looking at a situation where the free cash flow of our gas business being $100 million is what I'm caring about. It's not necessarily whether the production is up or down and whether people are putting on gas wells or not. Because it's too hard to keep track from our standpoint or give you guys a lot of the forecast.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's understandable. I'm trying to think about it from a more macro level, but appreciate the comments.

Operator

Your next question comes from line of Leo Mariani from RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just wanted to draw onto the Eagle Ford a little bit more. You guys talked about getting wells on quicker, with quicker drill times. Can you just give us a sense of what the timing is, in terms of how quickly it takes to drill and complete a well? You guys looking at 20 days, any kind of estimate you could give us? And just give us a sense of current well cost there.

James C. Flores

We're below 20 days, we've been as low as 16. But on average, say, 18, 19 days is probably fair. Making sure [indiscernible] doesn't kill me. But sub 20-day drills, and that's great efficiency [indiscernible] to happen. If you put more case in the ground, it costs more. So you got to be careful about all those efficiencies. At the same point in time, the big upgrade is the amount of frac crews and the overcapacity and the completion business and how [indiscernible] for market share, which is always good to see our standpoint in putting some really good execution on it, so we really appreciate that. So from our standpoint, we're working with our vendors to make sure we all get fair pricing and big, big [indiscernible]. But as for us, we're looking at a 20% reduction in the service cost next year, 2013. And how that gets allocated per well, it may be -- we may frac 10% more of the well. That's why I say it won't be a straight 20% decline in well cost at PXP just because of the engineering changes that we may undertake.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, got you. It's helpful. Additionally, just in the Eagle Ford, you guys are talking about going lower on the rig count and lower little bit next year. In terms of your production though, clearly it was up a ton this quarter from the prior quarter. Just trying to get a sense of how much of that is kind of realized efficiencies and quicker drill times and how much of that is these wells are just performing better than expected? I know it may be hard to quantify. But just any comments on how well the wells are performing versus your type curve here?

James C. Flores

Yes, good comment. You can't have that kind of performance without excellent well performance or a serious increase, a 50% increase in well performance, so -- on the production side. There's only so much you can do as far as accelerate a schedule and that type of thing. I think it's probably half and half, just off the cuff. We can dive in a little deeper, but from there, the well performance has been excellent. The redesigning of our fracs, adding more stages and less frac properties per stage has really helped our production. Each area is different. We're trying to tweak it and so forth, raise flexibility, the ability to come through with some excellent production results. But again, that obviously costs a little more. But when the constructions are cheaper, that's when you want to take advantage of it. And the point about the reduced rigs, I think we can drill more wells than we had planned with less rigs. And that's where your efficiencies really hit your leverage. So remember, our capital standpoint is also -- is being used for CapEx, but also for stock buyback. And when we use up $100, $110 Brent oil price next year, we want to have plenty of capital to buy our stock back next year as we do in this year. So that's the reason why we're being very mindful with our capital going forward. Now that's got some variables to it, if you put a bunch of rigs out there, [indiscernible] if we stay at 8 rigs or that type of thing, there may be $100 million one way or the other in capital toward the year-end. But we'll just deal with that when it comes about. But that's going to be oil-price driven, as well as CapEx plan-driven.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you, it makes sense. In terms of spacing in the Eagle Ford, any updated thoughts on what you think the ultimate spacing is going to be? Obviously, EOG had some success with down spacing recently? Just wanted to get PXP's thoughts on that.

James C. Flores

I think we're right on the line with EOG and the rest of the players in the eastern side of the Eagle Ford. We're looking at 400 to 500-foot spacing between laterals as being very comfortable at this point in time.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you, okay. Quick question on California here. It looks like your production was kind of flattish with the prior quarter. I know there were some downtime in the prior quarter as well. Does that linger into the second quarter here? And obviously, you guys are anticipating that. Your exit rate starts to move higher unto the end of the year. I just wanted to get a sense of whether or not you had continued downtime in 2Q there?

James C. Flores

Well, what happened when you move out, the drilling out there and the rigs out there, you're going to get production interruption. Downtime, I guess, it's the same. It was true downtime shutting in the first quarter, you'll see more production interruption in the second quarter as the rigs move out in the third quarter, then all that comes back. So no matter whether you're saying that rig interruption or downtime, it's irrelevant to you, it's all the same. But a little worse production interruption, and we think production in the third, fourth quarter that respond [indiscernible] riding along with plan. Very predictable.

Operator

Your next question comes from the line of Dave Kistler from Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly, just to kind of tie up the CapEx side of things. You've got production increase, CapEx run rate, year-to-date, let's call it, maybe 100 -- $850 million keeping that CapEx budget flat. Can you talk about the variables around that? Do you look at CapEx declining due to some front-end loaded CapEx, or as you highlighted, before oil prices go up, CapEx goes up? Just more color around that would be great.

James C. Flores

I don't think you'll see CapEx declining. I think you'll see in certain asset areas CapEx declining, like in California, you'll see asset CapEx on an asset basis expanding in the Eagle Ford. One of the big variables that we have $60 million allocated for Phobos in the fourth quarter. If Phobos flies [ph] through the first quarter, there's $60 million right there that of additional spending that could soak up any kind of potential overage in the Eagle Ford. So those kind of variables that's kind of hard for us is, okay, the CapEx is here, even though the CapEx spending in the Eagle Ford is going to be strong, the drop-off in California seasonally. And then of course, it obviously started in the Haynesville, in our gas business, we're moving that capital over as well. And we have some unallocated exploration that we don't find a project that we want to do then we'll go to Haynesville. So we've got about $100 million worth of unallocated CapEx right now. If you push Phobos into the first quarter spud, all indications are still fourth quarter. And -- but it's just a matter of capital budget. And so with that $100 million to the plus side and then hearing about more rig activities from EOG, that could all canceled out, which should be right around $1.6 billion, but we will see if it turns out with Phobos in the fourth quarter and EOG drills all the wells and we completed a bunch of wells, we may be $50 million to $100 million above our CapEx in the fourth quarter. But again, we can control that, and we'll only do that if oil prices are above $100 on the Brent side and we're able to execute our stock buyback program. So we're just kind of tethering in. We're really excited about the way the production is giving us the flexibility to have this corporate flexibility of how we're going to do things and just continue to execute our plan.

David W. Kistler - Simmons & Company International, Research Division

And would that CapEx that did pick up impact your thought process on the share buyback for the second half of this year?

James C. Flores

Absolutely not.

David W. Kistler - Simmons & Company International, Research Division

Okay. And then switching back to California just for a second where you spoke about the production interruptions for the second quarter. If I understand correctly, those are typical when you increase your drilling activity in order to get the appropriate production responses in the future. Is that correct? And if that's the case, isn't that kind of according to plan?

James C. Flores

Yes, that's according to plan. What happens is it always begs the question, because the flat line production quarter-to-quarter. And that's what begs the question, because usually when you're putting rigs to work in most oil fields, you're increasing production. While there in California, you got flat until you pull the rigs out. That's when the production goes up. You live there. You understand how it works out there.

David W. Kistler - Simmons & Company International, Research Division

Yes, perfect. Okay, and then last question on the Haynesville. Are you guys still going non-consent on some of the wells that are out there, or the wells that are being pushed forward? Any [indiscernible] change in that.

James C. Flores

We've not considered every well since March.

David W. Kistler - Simmons & Company International, Research Division

Okay, okay. And no thought process to changing that going forward, given gas has gotten a little bit better?

James C. Flores

Did gas go above $4? I'm just trying -- no, there's no change. We'll continue to harvest and enjoy our hedges there and free cash flow. That's -- until we get back to some fundamental pricing. Remember, we have 1,000 square miles of gas in 11,000 locations. If we end up with 10,800, that's not going to change anybody's world.

Operator

Your next question comes from the line of Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Going back to the Eagle Ford, in some of your past slides, you've talked about peak production rates, plateau production rates between about 30,000 and 35,000 BOE a day. You've got very, very strong rates here. Should we assume that there is meaningful upward potential there, or how are you seeing that peak rate?

James C. Flores

The peak rate is caused by a lot of things, Brian. Capital, schedule, wells on, well performance and so forth. One thing I can tell you is that our well performance is significantly higher than when that plan was designed and so forth. So the well capability, answer is yes. It all depends on schedule and capital.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got you. I mean I guess to the degree that you were drilling the same number of wells or the same number of wells relative to lateral length, and your wells are 50% better performance-wise, would there be any reason why that wouldn't rise by 50%?

James C. Flores

I think that's just math. I think the big dilemma is whether oil prices are there so we can fund an aggressive program and so forth. That all looks like intact as well.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then can you talk about any updates on the new venture side in Maori [ph] plans for Nevada or other areas?

James C. Flores

No, we haven't initiated anything along those lines. That's going to be a 2013 event, Brian.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay, great. And then lastly, Haynesville Shale-wise, I know it's not your focus. But can you just talk about your -- whether your non-consenting wells, or kind of how you're going about it and what you're hearing from your major operator in terms of drilling plans?

James C. Flores

Well, our major operator aspect, they say go with 2 rigs, we got 2 rigs. I mean there's really no activity in the Haynesville. There's 1 rig that's off running in the Chesapeake, so it's like -- there's not really any activity that the HBP Strategic Holdings series is over. It's all about how you want to manage your business and close. I mean everybody's got their own book to balance. We don't have any firm transportation from them as we don't have any outside reasons to either -- other than pure economics, whether we want to outtake capital to the Haynesville or the Eagle Ford, and that's a pretty good decision right now with $105 Brent.

Operator

Your next question comes from the line of Marshall Carver from Capital One Southcoast.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

A couple of questions. You talked about drilling longer laterals. What lateral length are you drilling in the Eagle Ford right now?

James C. Flores

We've gone from 5,000, say 4,500 to 5,500 to 6,500 kind of when -- it depends on lease [ph] lines and things like that. So we've add another 1,000, 1,500 feet, say, at the max.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

And then that's from what, the back half of last year to now?

James C. Flores

Yes. We started doing it in the first quarter, but then you kind of weighed in there lightly couple of drills and so it's now become more of a consistent process. And we did longer laterals and more stages with less frac material that seems to be the right combination for our area of the Eagle Ford.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay, great. And do you have the number of wells put online in the Eagle Ford in 2Q?

James C. Flores

Yes. [Indiscernible] everybody's -- consistency, it would be 36, Marshall.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. And I assume that's on a gross basis?

James C. Flores

Yes. 36 on gross, yes. It will be something -- We'll get you a net figure in a second, too. Probably 30 net.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. On the -- with the big ramp up in the Eagle Ford production in 2Q, you're basically right near your prior year-end exit rate target. What sort of exit rate target is cooked into your guidance now, or would you be willing to give a new exit rate target?

James C. Flores

Let's say the world all holds together, somewhere around 30,000 would be pretty easy -- pretty easy to get to, Marshall. Now, it's not like the world's had enough uncertainty and everything, and our alternative against the spend in the capital in the Eagle Ford, the Eagle Ford's ramp is doing exactly what we plan to do of times 0.5 -- 50% factor. So it's actually got Lucius coming along so that the big thing is to make sure we are able to press a number of shares. So our plan is working fine. We don't see -- all we worry about is the downside to the world economy in oil prices. If Brent goes to $80 and WTI goes to $60 for a period of time, we're going to curtail CapEx to make sure we're able to buy our stocks. So that's kind of -- that's the reason why our CapEx, we're squeezing as hard as we possibly can.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. And one last question. Was there any production associated with the asset sales? I know there was a small asset sale. Just wondering if it had some production associated with it, too?

James C. Flores

It's a few hundred barrels. But no, it was [indiscernible] Eagle Ford [indiscernible] at this point in time.

Operator

[Operator Instructions] Your next question comes from the line of Ron Mills from Johnson Rice.

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

A couple of quick questions. On the Eagle Ford, have you moved mostly to pad development on all your acreage? In terms of -- is that what's been driving the efficiencies?

James C. Flores

Yes. Well, we did a pad for about the best part of this year on everything, because every step-out well we drill, we can get -- permit 4 wells at the same time, but they'll pad big enough now. Effectively, we may have initiated as a non-pad but everything turns into a pad. So -- and I think at this point in time, the biggest thing is the production facility infrastructure we have in place, given the scale size, pipelines, those types of things. And then the ample services, I mean we've got guys beating our -- showing up everyday, can I come frac new wells? Instead of us trying to find them. So the number of days to hook up have gone down dramatically. Doss, what are we looking at now from our standpoint per well?

Doss R. Bourgeois

Our total turnaround time with the wells is probably 45 days to drill and then get on the first production. And we were still kind of earlier. It would have been in the 60, 65 days. It was just -- it's compressed a lot.

James C. Flores

That's compressed 50%, Ron.

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

Right. And how much more is -- you kind of drill well on paper, are you -- do you think you're pretty much getting close to as efficient as you can get, given your on-pad development, or do you think there's still a little bit more to squeeze out of that orange there?

James C. Flores

Well, it all comes with your rig count. If your rig count, let's say, the rig count goes up to 12, there's a lot more efficiencies to take out of it. The rig count stays at 8, we bring it down to 7 and we're drilling more wells, by -- I think by end of next year, our 7 to 8 rig program will -- by the end -- by middle of the third next year will have gotten all the efficiencies out of it. There's still efficiencies left to get. There's still, obviously, production facilities. And that's where our big uplift is, when we get our production facility infrastructure in place. But we won't end the year with more than a 60-day inventory of wells, because of frac with all those. So we're -- everybody is -- it's easy to have -- to build efficiencies when you have ample services, willing service providers, they're doing a great job for us and so forth and doing it safely. That's the key. So we're getting good cooperation by everybody just because of, I'm sure, the gas drilling slowed down so much.

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

Okay, great. And then on the EOG AMI, you just talked about them being at 2 rigs on that acreage now. They've been as high as 6. So it sounds like you have 8 operated, and 1 net operated on -- or non-operated on the EOG AMI, what -- any additional...

James C. Flores

Let me be clear there. They're never been at 6, they're talking about going to 6. And our guys are planning with their guys. We're all just trying to stay in synch. And remember how that deal works is that they have total flexibility, we have total flexibility. There's no like set budget early in the year and that type of thing. We may get to that at some point. But they've got their lease demands and their rig and their operational demands, we have ours. And this thing was so wild in the beginning that we said, look, you guys do your part, we'll do ours, we'll just respond. So that's still the game plan. So we're hearing they made -- they build a bunch of rigs in the third and fourth quarter. We haven't seen it yet. So we just don't -- it's hard to say that, that CapEx is going out the door.

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

No, good that answers -- I was going to ask you what drives that decision. And then 2 more quick ones. On the Eagle Ford, the service contract, the services side, rig in pressure pumping, obviously more available. Any talk with any of those guys about locking in term on some of those pressure pumping contracts, or is spot still the way to go from your standpoint? I know they probably wouldn't like term at this point, but when you look at...

James C. Flores

We have another category, we call it relationship. We build relationships with our vendors. And somehow and sometimes, it requires a contract to develop some financing and have the equipment show up sometimes. Sometimes it's well to well but it's continued. You do a good job, we do a good job. Our main goal is to stay well financed and be able to provide them the invoice support, we call it, invoice on a timely basis. Their job is to provide the services. And I think what we're pushing toward is a more quality-oriented service relationship versus just pushing prices as low as possible because of the oil margin. And that quality-oriented relationship is about downtime, it's about equipment, it's about people, it's about safety and everything because we've got probably almost 200 employees down there at this point in time. We've got 2,500 service hands. It's -- we're very much dependent. The whole industry is on that, and so we try to drive that message versus lowest cost provider because that's -- and take our height out of the well performance.

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

Okay. And you said by the middle part of next year, you'll be -- you should be substantially done with the central facility construction?

Doss R. Bourgeois

We'll be done with our central facilities at the end of this year.

James C. Flores

This year. That's accelerated also, Ron. We've been talking second quarter last year. And -- but again, equipment available, people available, efficiencies on that area as well. It looks like we're going to be completed by year-end this year.

Operator

Your next question comes from the line of Leo Mariani from RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just a couple of quick follow-ups here, guys. Can you give us a little more color on the DD&A rate on the third quarter -- I'm sorry, in the second quarter. Obviously, it was up a bunch. I know that was a function of some write-downs. How should we expect DD&A to play out in the second half of the year?

Scott D. Winters

I don't really -- we don't see DD&A doing that much. Really, we have to wait until the end of the year to get our -- do our reserve report, and we'll know a little bit more then. But we don't really see a lot of movement from the unproved to the proved, just because the big move that was really in the first quarter. Actually the futures prices, which really drive the movement from the unproved to the proved, has actually improved in the nat gas world. Not very much, but it has improved a little bit from the first quarter to the second quarter. So we don't see a lot of that movement. It's really going to be drilling and what happens to our drilling reserves going forward between now and the end of the year and what the end of the year reserves look like.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you, okay. And just any update on what your plans are with McMoRan stock?

James C. Flores

No update at this point in time. We're like everybody else, waiting on well tests. The well tests, once it happens, then we were waiting on Lion Creek, we're waiting on Blackbeard, West Blackbeard. The whole onshore deal of Highlander, [indiscernible] and so forth some of the things we've been looking at for the last year that haven't been able to talk about that's coming. McMoRan is executing their program. And from our standpoint, we're happy shareholders.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, great. And I guess any update on the rest of your Gulf prospects in the Deepwater? Have you seasoned any of them further at this point? Do you have any kind of further thoughts about the few prospects you'd picked up with the lease sales several months ago?

James C. Flores

Yes. We obviously got 12 of those coming up at year end. Really, we'll know where it is in the first quarter. But standpoint [indiscernible] and tying up some loose ends on those, looking for late 2013 maybe 2014 drills on those were scheduled. And then intermittent between that, we've got completed the Dutch on the Anadarko radar at some point in time. It's not on anybody's schedule. Our goal is by the end of '14 to have another 4 wells drilled, prospects drilled behind Phobos. So from '13 -- late '12, '13 and '14, we're going to know a lot about the pricing trend and have -- hope to have multiple [indiscernible] coming along for the second half of this decade.

Operator

Thank you. At this time, we have reached the end of the allotted time for questions and answers. I will now turn the conference back over to management for closing remarks.

James C. Flores

That's great. I didn't know we had an allotted time, operator. Obviously, we're keeping [indiscernible] aside around here guys.

We really appreciate everybody's interest in the company and hope everybody is having a good summer. We look forward to seeing everybody this fall, and -- as we continue to rollout better production out of our oil assets. Thank you very much.

Operator

Thank you. That concludes today's conference call. You may now disconnect.

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