Pioneer Natural Resources Company
Q4 2011 Earnings Call Transcript

Published: 7 Feb 2012

[Operator:]

Welcome, ladies and gentlemen to Pioneer Natural Resources' Fourth Quarter Conference Call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations. Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors then select Investor Presentations. Today's call is being recorded and a replay of the call will be archived on the Internet site through February 28. The company's comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release, on Page 2 of the slide presentation and in Pioneer's public filings with the Securities and Exchange Commission. At this time, for opening remarks, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Mr. Frank Hopkins. Please go ahead, sir.

[Frank E. Hopkins:]

Thank you. Good day, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Scott will be the first speaker. He'll provide the financial and operating highlights for the fourth quarter of 2011, another strong quarter for Pioneer. He'll then update you on the company's reserve replacement performance in 2011, and that will be followed by a summary of our 2012 capital program. After Scott concludes his remarks, Tim will discuss our drilling results and plans for the Wolfcamp Shale, the Spraberry field, the Eagle Ford Shale and the Barnett Shale Combo Play. Rich will then cover the fourth quarter financials in more detail and provide earnings guidance for the first quarter. After that, we will open up the call for your questions. So with that, I'll turn the call over to Scott.

[Scott D. Sheffield:]

Thanks, Frank. Good morning. We're on the highlights on Page #3. We had another great quarter in the fourth quarter of '11 with adjusted income $147 million or $1.19 per share as compared to a consensus of $1.03. This does exclude some mark-to-market derivative losses of $22 million and also some unusual items of $1.94, $236 million. Fourth quarter production, we were at the high end of 140,000 barrels of oil equivalent per day. We are moving South Africa into discontinued operations. That would put us at 137,000 barrels of oil equivalent per day. We have a process that's underway and should be completed by the first half of 2012. That will be the divestment of our only remaining international asset. Again, production was up 12,000 barrels of oil equivalent per day, up 9% versus third quarter. Also, 19% quarter-to-quarter on oil growth primarily related to growth in the Spraberry, Eagle Ford Shale and the Barnett Shale Combo. For the year, we averaged 124,000 barrels of oil equivalent per day. This includes our discontinued ops in South Africa. We're up 14% versus year end -- for the full year of 2010. If we exclude discontinued ops, we're up 16%. What's more important, and Tim will talk more about it in detail, we drilled our second successful horizontal Wolfcamp Shale well, performing exactly like the first well. Both wells are above expectations. This will probably end up being one of the largest oil shale plays in the U.S. We are the largest acreage holder in that play with well over 400,000 acres. We're continuing our successful deeper drilling to the Strawn, Atoka and Mississippian, with about half our wells going into these areas or more in 2012. Continuing to add additional frac capacity totaling 70,000 horsepower in both Spraberry and Eagle Ford in the fourth quarter. Again, delivered great drillbit finding cost, drillbit reserve placement, 313% reserve replacement, 148 million barrels of oil equivalent and a drillbit finding cost of $13.83 per barrel of oil equivalent. Also a big achievement

[Timothy L. Dove:]

Thanks, Scott. We did have a very strong operational quarter in the fourth quarter of 2011 across our entire asset base and that includes our assets in Raton and the Mid-Continent area. But for today's purposes, I'll be talking principally about our Texas-based growth assets, and I'm going to start with discussions regarding the horizontal Wolfcamp play. Although it is early in the play, we're continuing to see encouraging signs. And specifically in this report, we're talking about a second horizontal successful well that was in the neighborhood of 1.5 miles away from our first well. The wells were completed and drilled and designed essentially to be identical and what we've seen, importantly, is almost identical results. Now they only were drilled to 5,800-foot lateral lengths, that's considerably less than we'll be drilling as we go forward, and I'll talk more about that in a minute, and with only 30-stage completions. With that said, we're very confident that, with our use of microseismic, that we once again successfully landed the wells or successfully have the fracs in the entire 500-foot -- 800-foot zone, so it's actually going exceptionally well in these 2 wells. And you can see that as you go to Slide 11 in which case we show the production from these wells in their early stages. And you can see they're almost identical, as I mentioned earlier. What's really important about this production to date on the first well is that, after about 90 days, we've seen about 45,000 BOE of production in that well. That's about 7x what we would expect from a normal Spraberry vertical well over that same 90-day period. So that 7

[Richard P. Dealy:]

Thanks, Tim. I'm going to start on Slide 21. As Scott mentioned, we had a net loss attributable to common stockholders of $111 million or $0.93 per diluted share for the quarter. It did include unrealized mark-to-market derivative losses of $22 million or $0.18 per diluted share and unusual items totaling $236 million or $1.94 for the quarter, principally noncash items related to reduced gas prices. Adjusted for these items, income would have been $147 million or $1.19 per diluted share, as you can see on the slide there. Looking at the bottom of the slide, we show our guidance coming into the quarter that we gave out in November, relative to the middle column there that shows fourth quarter including South Africa but excluding unusual items. So going down that list is briefly on the highlights. Production was at upper end of the guidance, as Scott mentioned. If you look at exploration and abandonments, it's at the higher end of the range principally related to seismic data that we acquired for our horizontal Wolfcamp play in Spraberry. And then G&A was at just above guidance related to performance-related compensation. The other items are basically in line with where we forecast coming into the quarter. Turning to Slide 22, price realizations. You can see on the bars there that oil was up 5% for the quarter to $91.51; while NGLs and gas were both down for the quarter, with NGLs declining 6% to $45.70 really as a result of declining ethane prices during the quarter; and the natural gas prices were down 17% to $3.37 per Mcf. At the bottom of the slide here, you can see the impacts of derivatives and that's there for your information. Turning to Slide 23. I think the punch line here is that, really, production costs, if you look at each of the quarters in 2011, they were virtually flat throughout the year, with fourth quarter being on top of where the third quarter came in. Probably, the one item of note there, if you look at third-party transportation costs, they were up in the fourth quarter mainly as the result of Eagle Ford ramp-up and production. We had higher trucking and treating costs there. Turning to Slide 24. A great balance sheet at the end of the year. We had $537 million of cash on the balance sheet, a net debt of $2 billion. Our credit facility of $1.2 billion is completely unused so, as Scott mentioned, net debt-to-book capitalization of 26%. And if you think about the forecasted $2.2 billion of expected cash flow, we have very strong coverage metrics, as well. I think also that, during the quarter, we moved up to investment grade rate by S&P, which, as you know, reflects our continuing to improve our balance sheet. Turning to Slide 25, first quarter production guidance. 141,000 to 146,000 BOEs per day, up from where we ended the fourth quarter. And then, exploration and abandonment is higher than our normal range to $35 million to $60 million really because it includes 2 items. One, we got 2 Alaska exploration wells going down this winter and then we also are shooting some additional Wolfcamp, horizontal Wolfcamp seismic in the first quarter. All of the other items are the same as what they've been in prior quarters, other than current income taxes that is down with moving South Africa to discontinued operations. Current income taxes represent state taxes that we'll pay during the first quarter. So with that, we'll stop here and open up the call for questions.

[Operator:]

[Operator Instructions] We will take our first question today from Brian Corales with Howard Weil.

[Brian M. Corales:]

A couple of questions. One, what do you all think, I know it's very early, but on the Midland basin horizontals, what do you think the optimum length is? I know you're kind of increasing the laterals. Do you all have kind of a length in mind or a number of fracs in mind?

[Scott D. Sheffield:]

Yes, Brian. As Tim said, we're moving up to about 7,000 feet, we'll probably try some a little bit longer. But one of the critical issues there’s only a certain amount of acreage, especially on university lands, that you can get these long laterals. I think the challenge for most operators is going to be several smaller independents will not be able to get up that long. So there’s going to be a lot of probably dealmaking in the play, but on university lands where we own a lot of our acreage to be the area to move out 7,000, maybe even 8,000 feet. So the Bakken has moved up significantly. So where you can move out longer laterals, we'll definitely try it.

[Brian M. Corales:]

Okay. And then you all did mention in the Eagle Ford with going more to white sand, a little bit away from ceramics. One, is there a rule of thumb? I don't know if it's depth or pressure where you're going to use white sand primarily. And then two, if we fast forward 6, 9 months, how much of the pressure pumping or the horsepower is going to be internally owned?

[Timothy L. Dove:]

Okay, well, first of all, I think it's clear that we feel like that the white sand is something that's going to be best used in areas that are a bit shallower and lower pressure as compared to the opposite. In other words, I think it's going to be a situation where it's north and west in the trend where we're dealing with a shallower horizon as well as less pressure. And so I think you'll see us, like, for example, as you get in DeWitt County, the Western DeWitt County area is definitely using white sand. As you get south and east, you get hotter, deeper and higher pressure and that becomes an issue. So you’ll see us using ceramics potentially to the southeast and sand to the northwest, in a general sense. In terms of horsepower, our second PXD-operated frac fleet is just right now getting cranked up. And that will have us at a point very shortly where we'll be pumping 2/3 of the wells with Pioneer equipment for the rest of the year.

[Brian M. Corales:]

And can I, just to kind of follow on that, I mean, assuming white sand and, we'll say, 2/3 of the pressure pumping with internal, what does that do for PXD's well cost?

[Timothy L. Dove:]

Well, as you know, we've been using a blended well cost of $7 million to $8 million, something like that, but that includes internally generated pumping services as well as a combination of ceramics and white sand. If you look at the savings on white sand, it's about $700,000 per well. We think we can pump the wells at least $1 million cheaper than a third party. And so that should give you a handle on kind of what we're coming out on the cases where we just use white sand and our own pumping services.

[Operator:]

We'll take our next question from Brian Lively with Tudor, Pickering, Holt.

[Brian Lively:]

On the Eagle Ford volumes, it sounded like you guys were at the lower end of your Q4 guidance, but it seems like the issues are transitory. If that's true, just correct me if I'm wrong on that, but what is the exit rate for 2011 Eagle Ford volumes?

[Timothy L. Dove:]

Well, let’s see. I can talk to you about what happened, Brian, real quick in the field. We had a couple of situations which, I believe, are in fact transitory. We had a situation on some of our oilier areas where we were having some paraffin-related issues at the CGPs, which have now been alleviated with chemical treatment, so that was inhibiting some production, and so we got that back to normal. Also, we had a couple of situations in our CGPs where we were dealing with some high-line pressures during peaking operations. And accordingly, we were having to review, in fact, we're in the process of reviewing adding central compression to alleviate that problem. And that's something that's under, that's we're doing as of right now, we're actually in the process of evaluating putting in central compression. So basically, as you said, we're in a situation where these are just transitory issues that we're just solving.

[Brian Lively:]

And do you have a exit rate for the Eagle Ford?

[Timothy L. Dove:]

Well, it's bigger than 20,000, I promise you that.

[Brian Lively:]

Okay, is it bigger than 25,000?

[Scott D. Sheffield:]

We just don't give out exit rates, Brian, so...

[Richard P. Dealy:]

Brian, it's about 20, like we talked last night.

[Brian Lively:]

Oh, I told you I would try, Frank, anyways, so.

[Frank E. Hopkins:]

I know you would.

[Brian Lively:]

On the Wolfcamp itself, I'm curious on how you guys defined your original expectations. You guys say that the results are better than what you thought going in and I just wanted to get a sense of how you derived those expectation in context to the overall play itself and how you might see some variability in the rock quality as you go to the north in particular?

[Scott D. Sheffield:]

Yes, as you know, we have over about 900,000 acres in the entire Spraberry, Wolfcamp play. So we have access to over 7,000 logs and we probably got the most number of cores versus any other operator. We've been there for a long time so we probably have more data. We have some 3-D seismic data on the shelf, we're buying some more or shooting some more so our data source is probably 10x greater than anybody else. We have people focused on it. And we're in the center of the basin where the oil is mature. It's very brittle in the Wolfcamp play, as we have found out through the core analysis. So we have a pretty good feel on how big this play can go. So the reasons the Wolfcamp, as you get to the Spraberry theme formation, the gradient increases, and because of that, we're seeing much better performance, as Tim has mentioned. On the production characteristics, there’s both wells are still flowing, but at some point in time, we'll put them on either jet pump or pumping units, but they're flowing a lot longer than we expected. Pressure is staying higher. That's because we had a pressure regime change going from the Spraberry/Dean down to the Wolfcamp. So that's helped us also.

[Brian Lively:]

That makes sense. So then, the 2 wells, are those the expectations, then, going forward?

[Scott D. Sheffield:]

That's going to change. But we're over, we're drilling wells 80 miles, 70 miles apart in the play and we'll be drilling wells basically to the north, so we will have to develop. Probably, it wouldn't surprise me if we end up having 3 or 4 different type curves. In the Eagle Ford, I think we've mentioned before, we got about 15 different type curves in the Eagle Ford so we may have more -- as much in that, but we expect at least 3 or 4 different type curves.

[Brian Lively:]

Okay. And my last question. Tim, you mentioned a number of times about capital efficiency as you shift towards the horizontal program. Can you put that in context in terms of numbers? What is the breakeven cost that you're expecting for your average vertical well versus the horizontal program at this point?

[Timothy L. Dove:]

Well, I haven't computed the breakeven numbers. But I look at it in sort of a simplistic method of analysis similar to what I mentioned on the call, which is we think our development drilling run rate for a horizontal well at $6 million to $7 million, which has quite a bit of detail behind it, which represents something like 4x the capital of a vertical well is a good number. And the real question is then what is the productivity of the wells? We're simply, at this point, encouraged by the early production. I mean, when you have a 7x on production compared to the vertical well, you get pretty excited about that because it has the possibility that you are actually adding significant capital efficiency. The issue with this is we'll only know the real answer to your question as we have more time and more production history under our belt, so that we really know the answer to the question. What I'm saying right now simply is that it's encouraging, what we're seeing.

[Operator:]

We'll take our next question from Gil Yang with Bank of America Merrill Lynch.

[Gil Yang:]

Everyone, you commented for the second well that you, microseismic told you that all 800 feet of the interval was frac-ed into. Can you remind me of what you saw in the first well?

[Timothy L. Dove:]

Identical, Gil.

[Gil Yang:]

Okay. And can you talk about, with this well, the second well, the constraints are like the first well was?

[Timothy L. Dove:]

This well does not have any real significant constraints, and so from that standpoint, it differed a little bit. But right now, these wells are essentially, neither one has any constraints is what it amounts to.

[Gil Yang:]

Okay. Is that significant in any way? Is the fact that the first one was constrained, does that suggest that it's actually a better well, or you can't...

[Timothy L. Dove:]

I think you really can't read too much into it because the calculation of an unconstrained flow rate is simply that, it's a calculation, it's an estimate. So I think what we need to look at is how well these wells are producing. Right now that they've got several weeks and months under their belts in terms of data, is going to be the real illustrative point.

[Gil Yang:]

Can you calculate, based on pressure drawdown, when you're going to put the first well and pump?

[Timothy L. Dove:]

It looks like, right now, we're still producing the well flowing, as I said. I think it could be within the next few months we'll be putting on a pump is the current thinking.

[Gil Yang:]

Okay. And what kind of rate do you think you'll be getting when you put it on pump?

[Timothy L. Dove:]

I don't know the answer to that question [indiscernible]. I presume it to be higher. I can't tell you the number, though.

[Gil Yang:]

No, no, no. I mean, when -- does it drop off to 100 before you put it on pump? Or does it -- you do it at 300, or I mean, you can tell?

[Scott D. Sheffield:]

It's got to be 50 or less, I mean, or down to 0, maybe, so flowing pressure.

[Gil Yang:]

Okay, okay, all right. And for just a housekeeping question -- well, before I get to that. The 100 to 200 million barrel potential in it, it was that potential, it's not for that well, right? That's just the one well that is...

[Scott D. Sheffield:]

That well is looking at a 100 to 200 million barrel prospect within the shale. It'll take more than one well to develop it, but if it's a discovery and still there's spill, it could be as high as 200 million-barrels-plus.

[Gil Yang:]

How many exploration wells do you think you need to delineate that opportunity? How many wells would you need to drill to…

[Scott D. Sheffield:]

It's one well will determine that, and the size.

[Gil Yang:]

Okay. And then how many wells to develop it?

[Scott D. Sheffield:]

We'll have to get back with you on that.

[Gil Yang:]

Then for Rich, maybe, a housekeeping question. The share count seemed like it hadn't changed but you had this equity issuance. Am I missing something?

[Richard P. Dealy:]

Yes, the share count, as you can imagine, yields weighted average. So until we’re done at the end of the quarter, there's very really little of the new shares weighted into the calculation.

[Gil Yang:]

Even for the quarter?

[Richard P. Dealy:]

Well, for the quarter because you only had basic 15 days of it, yes, 15 or 90. And plus, since we had a loss, you don't get all the, you don't have a big dilution effect.

[Gil Yang:]

Okay. And so that's, is that part of it, that there's a certainly is some antidilutive nature of the, these logs?

[Richard P. Dealy:]

That's correct.

[Gil Yang:]

Can you quantify that?

[Richard P. Dealy:]

I don't have it here in front of me, Gil, but I can, we can get it for you.

[Operator:]

We'll take our next question from Leo Mariani with RBC Capital Markets.

[Leo P. Mariani:]

Yes. I just wanted to clarify a comment here on the Wolfcamp. You talked about the wells performing above expectations. You guys had an EUR range in these horizontal wells of 350 to 500 MBOE. So above expectations, would that be sort of above the midpoint, so kind of above a 425 number, or is that kind of above the high end at the 500?

[Scott D. Sheffield:]

Yes, we're signaling it's above the midpoint basically.

[Richard P. Dealy:]

Yes, that's right.

[Leo P. Mariani:]

In terms of South Africa, obviously you guys announced the decision to sell that today. I know, in the past, Pioneer has kind of said that they’d likely kind of produce that out. Is there anything that sort of changed your all’s mind here on that?

[Scott D. Sheffield:]

No. We've had, but we basically have had some contacts, positive contacts and we're working through the process. That's what’s changed.

[Leo P. Mariani:]

Okay. In terms of the Eagle Ford, did you guys see any changes in the EURs for your wells in your year-end '11 reserve report versus year-end '10?

[Timothy L. Dove:]

Now, we've been adding reserves, as you know, as a result of the large drilling campaign and the EURs are hanging in there.

[Leo P. Mariani:]

Okay, and so roughly similar EURs there?

[Timothy L. Dove:]

That's right.

[Leo P. Mariani:]

Okay. And I guess, obviously you've talked about bumping up your CapEx a little bit here in 2012 to add some midstream. I guess, as you grow the Spraberry here, is that something you think might have to recur in the next couple of years, we may have to add another few plants every year or so? Can you just kind of help us out with that?

[Scott D. Sheffield:]

No. We and analysts were talking, and since we are partners on 2 of the big 3 plants in the Spraberry play, we actually got them to increase. They came to us with a $100 million capacity. We got them to double it to $200 million, but a lot of it has to do with this ramp-up in the horizontal Wolfcamp play. It looks like the EURs are running at about 1,000 in that play. But when you're making a lot more oil, you are going to add a lot of casing head gas. And so and for that reason, and then we have another partner up in Martin county. We got them to increase that significantly also in another plant that we own in Martin county that's coming online here in the next few months because of the success in the deep vertical play by going to the Atoka and Strawn and Mississippian. And so this should, adding 200 million a day in Midland county and adding another 120 million a day in the new plant up in Martin county, it should give us plenty of capacity for the next several years.

[Leo P. Mariani:]

Okay. And I guess, are these facilities that you guys are partners on, and you own like 1/2 of these roughly, is that right, hence the CapEx?

[Scott D. Sheffield:]

27% on 2 of the plants and about 30% on the other plants, so roughly around 30% in all 3 plants.

[Operator:]

We'll go next to Michael Hall with Robert W. Baird.

[Michael A. Hall:]

Just quickly, I guess, in the Eagle Ford, it makes a lot of sense obviously to defer the dry gas activity. I'm a little curious as to why not kind of, I guess, reallocate that within the Eagle Ford to more liquids-rich opportunities. And are there kind of just logistical constraints to that or midstream or what's the thinking around that? And then also, is there any potential acreage loss associated with that reduced dry gas activity?

[Scott D. Sheffield:]

Yes, the second part of your question, I think Tim did mention that there is a few thousand acres, not much, that we are dropping. I don't expect anybody to pick it up so we always have the opportunity at some point in time to go back and pick it up as acreage costs come down. On the first part of the question, the primary driver. We did not increase Barnett and also Eagle Ford even though the economics are great is that we just didn't want to increase our CapEx. We have the bank facility to be able to do it but we just don't want to get into a big overspending mode. So to me, we're already growing 23% to 27% and which we just don't think we'll even get paid for if we grow anymore, much more than that, too. So it's a combination of capital efficiency and those bigger reasons.

[Michael A. Hall:]

Okay, makes sense. So it's just basically kind of stay within cash flow and not get too far ahead of yourself.

[Scott D. Sheffield:]

Exactly.

[Michael A. Hall:]

I guess in the Wolfcamp, a couple of quick questions. When would you expect to test that acreage out near Arian [ph]? I mean, like, right on the border of Reagan in the Arians [ph]?

[Scott D. Sheffield:]

We're going to be testing essentially our entire 200,000 acres by the end of '12. It’s only an hour down south. So we’ll eventually move out to the southeast at some point in time.

[Michael A. Hall:]

Okay. And then in Slide 11, in the footnotes there you provided, a couple of different NGL yields. I'm just curious, sorry if I'm not reading it correctly, but which one should I be thinking about as the more likely case? Or should it be somewhere in between them? Or how should we think about that?

[Timothy L. Dove:]

Yes, I think the first one, the 215 barrels per million and 42% shrink is the one that's probably the more generic answer.

[Michael A. Hall:]

Okay. And then finally, I guess, are you all targeting any other or still thinking about targeting any other horizontal intervals? Or are we kind of hands full with the Wolfcamp at this point and...

[Scott D. Sheffield:]

Yes. We have talked about in the past, these are on this call or individual meetings, about there is some activity by other operators in the horizontal Atoka. So we expect at some point in time the team is working up potential locations for that, and we also have a team looking at other shale plays in the area. So we think, with the Spraberry in the Midland basin at 20% of the U.S. oil reserves, that there’s huge potential in other shale plays in the basin.

[Timothy L. Dove:]

One addition to that is we are looking at the potential of actually go in one to the existing Spraberry pay zones called the Jo Mill, which we think also could be an area where horizontal drilling could enhance productivity. So that is something we'll probably do some, a couple of wells in this year. It's still under planning.

[Michael A. Hall:]

Okay, great. I guess, actually, one last one for me. I think you said 750 wells in the vertical program. Is that a gross number or net?

[Timothy L. Dove:]

That's gross numbers. I mean, net and gross are essentially the same for our Spraberry vertical drilling.

[Operator:]

We'll go to our next question from Dave Kistler with Simmons & Company.

[David W. Kistler:]

Real quickly, in the Wolfcamp, you'd talked about it as potentially being your biggest oil play in North America. Where do you ultimately see rig count going there not just for yourselves but maybe industrywide? And then given you guys have your strategy of vertical integration, will you be looking at picking up higher-horsepower rigs to do that kind of drilling over time? Can you just kind of give us a little more color around that?

[Scott D. Sheffield:]

Yes. It definitely has huge potential. I think the things that we're going to -- the main thing that's going to hold it back is the current land position. Most of it's held by, except by ourselves, or just a very few small, large operators. It's not -- it’s totally different to Eagle Ford where people can come in and buy a lot of acreage. You cannot buy a lot of acreage in this play. And so it's going to take a massive effort to be able to put together small independent operators. A lot of people just have, they may have a Spraberry well on a 40-acre or 80-acre tract. The problem is you got to put together 1.5 sections or maybe 2 sections before you can even drill an economical horizontal Wolfcamp play. And that's going to be hard for a lot of people. So this play for that reason will probably go much slower than the Eagle Ford but it's got the potential to ramp up eventually to easily 100 rigs over the next 3 to 5 years and maybe even 200 rigs, but it's going to be a much, much slower pace versus the Eagle Ford play simply because of the current land position. And most of our rigs that people have to pick up are 1,500-horsepower, there's very few of those out in the Permian basin so these either have to be new builds or come from plays like the Haynesville. So we got to see a continued significant drop in the dry gas rig count in these plays and that will allow the Wolfcamp play or the Wolfcamp play over in the Delaware Basin also to pick up a lot of these 1,500 horsepower. So there is a shortage of 1,500 horsepowers for that reason and so another reason it's not going to ramp up as fast as the Eagle Ford.

[David W. Kistler:]

Does that mean you guys are going to pursue potentially picking up some 1,500-horsepower rigs on your VI strategy? Or are you going to be looking to contract at this point?

[Scott D. Sheffield:]

The ones that Tim mentioned already going up to 10 rigs, we're contracting to going up to 7, 8. By the end of the year, this year, going to 10, we'll be contracting. Most of them have already been contracted.

[David W. Kistler:]

Okay, that's helpful. And then, you've done 34 rigs on downspacing in the Permian and waterflood results continue to get better on the margin. When do you guys kind of call victory on moving from 40-acre to 20-acre spacing? And when do you start prosecuting maybe a more aggressive waterflood?

[Timothy L. Dove:]

I think the fact is we're continuing to drill 20-acre space wells this year and next year and the results look very, very good. And I think we've proven that this technology where we're deepening 20-acre wells and creating production, which is essentially equal to offset 140,000 BOE locations that otherwise were not deepened, is something that's going to work, going into the future. We'll be continuing to drill some 20-acre wells this year. I think the objective still is we've got several thousand 40-acre wells to drill so we may as well focus on those first. I think the fact is we've proven that 20-acre locations are going to be economic. On the waterflood, we're still continuing to see very good results and I'm starting to see additional response in other wells that had not yet responded. And so I think that's gone exceptionally well. We have a team of people that are working on about a 20,000- to 25,000-acre flood that we may be contemplating starting up here at the end of the year, a little later in 2012. But suffice it to say, I think we can call it a success. And right now, we're just assessing which next direction we're going to go. I think it would be later this year before we pull the trigger on that.

[David W. Kistler:]

Great, that's helpful. And then in the Spraberry where you're looking at co-mingling various zones, can you talk a little bit about how these overlap? You've given us prospectivity for each area, but can you talk about how much of them overlap just so we can kind of think through how we'd model out field development on a longer-term basis?

[Timothy L. Dove:]

I think, if you look at the slide that I was talking about, Dave, Slide 15, the important point about this slide in terms of overlap is you, typically, it's very seldom that you see a situation where you have both Atoka and Mississippian, just the way the aerial extent is. So into the extent that we're drilling a Strawn well, this would be more areas to the central and the southern part of the acreage. As you go north, you encounter Atoka and Mississippian, in a lot of cases, Strawn as well. And so what you have to realize is you can't just sum Strawn, Atoka and Mississippian. But in many cases, you're going to have the ability to complete in both the Strawn and the Atoka or in the Strawn and the Mississippian.

[Operator:]

We'll go next to Amir Arif with Stifel, Nicolaus.

[Amir Arif:]

Guys, just a few quick questions. First, in the Wolfcamp Shale, can you tell us what the liquids cut is for the Wolfcamp Shale wells versus your typical vertical wells?

[Scott D. Sheffield:]

They're both about 90-10, so 90% liquids, 10% gas. The Wolfcamp may be a tad higher than the vertical well. And it's got also higher Btu content so far on the first 2 wells, so moving toward 1,500 Btus versus 1,400 on a vertical well.

[Amir Arif:]

Okay. And can you just give us some color of how you see the geology or the expectations as you move further southeast from where you did your first 2 wells towards Reagan County and [indiscernible]?

[Scott D. Sheffield:]

Well, I mean, it's obvious because we have 60, 70 wells that have already been drilled by other operators. So we have that data and a lot of that data has to be filed with university lands. And we already have access to that data so that's why we're highly encouraged even though we have logs in the area. But the production results from both El Paso and also EOG are very good results.

[Amir Arif:]

But do you expect them to get better than your original drilling area or...

[Scott D. Sheffield:]

I think in the -- we've seen some curves overlying our curves. The wells are coming in about the same. But I think, because we're deeper, that it looks like that we're already -- you have to look at the same wells with the same lateral to get apples and apples. It looks like our Giddings wells, based on their lateral lengths and the depth that they’re in, are doing better than these other operators. The reason is, is that we're a little bit higher depth so we get a little bit better pressure regime. But as we move toward them, we should have similar expectations.

[Amir Arif:]

Okay, sounds good. And then just a question on the vertical side. As you -- I mean, you’ve been co-mingling all the way down, but as you go to some of these deeper zones in the Atoka or Mississippian, are you still able to co-mingle all the zones? Or do you have to sort of add the zones one at a time in terms of the shallower zones?

[Scott D. Sheffield:]

Yes. We are allowed to co-mingle all the way down not including the Atoka so we can co-mingle the Strawn. And we are going into commission in February and March for a new set of field rules to allow us to co-mingle all the way down to the Atoka. And we're also coming up with a set of field rules for the horizontal Wolfcamp play and those have been filed. Hearings are in February and March.

[Amir Arif:]

Okay. And then just one quick question on the Eagle Ford, just in terms of the dry gas acreage exploration. Is that going to be a -- is that a bigger issue in '13 or was '12 a big issue? I'm just trying to figure out what percentage of your drilling CapEx in '13, based on what you have so far, is going to be dry gas.

[Timothy L. Dove:]

Of course, we haven't made decisions on 2013 yet but we will face more expiries of leasehold if we were to decide not to drill a significant number of dry gas wells. Remember, I mentioned earlier in 2012, we were talking about drilling 25% of the wells at a dry gas zone, other than from the fact we've had this gas market we've been facing. So now we're down to about 15% of the wells. We would have to drill a higher percentage next year to preserve leaseholds, so to the extent we do not drill more than 15% this year, we will not have significant loss of acreage. We could have higher acreage amounts lost next year if we were to do the same.

[Amir Arif:]

Okay, so that you're not really pushing that '12 drilling over to '13 right now. Are you letting a little bit of that expire to '13...

[Timothy L. Dove:]

It's very insignificant. We're also working on trying to renew some of these leases with cash, which we think is the better way to go than drilling wells on the leaseholds, and to the extent we can do that, we will. But that would leave us having a relatively low amount of acreage that we'd have to expire, less than 10,000 acres.

[Operator:]

We'll take our next question from Brian Singer with Goldman Sachs.

[Brian Singer:]

A couple of questions on the gas percentage in the production mix, one is just following up on the last question there. If you look at the first Giddings well in the Wolfcamp, how, if at all, has that percent of gas in the mix has changed especially in recent days? And do you expect any change over time relative to the 30-day rate you've reported from the first 2 wells?

[Scott D. Sheffield:]

The gas-oil ratio on both wells are about 1,000. On our first well, we did not have the test results back on the composition of the gas so we used roughly a Spraberry vertical well in the initial NGL calculations, so it turned out we were low. So the first well and the second well are the same. The Btu content is moving toward 1,450 to 1,500 Btus in both wells versus 1,350 to 1,400 in a typical Spraberry well. So we gave out a vertical well composition with our first horizontal well. But now, with the composition of both wells taken, they're both up to 1,450 to 1,500 Btus.

[Brian Singer:]

And should we expect a greater decline in the liquids relative to the gas? In other words, should over time as the well that goes through its normal life, it should become a little bit more gassier or do you think that, that ratio holds?

[Scott D. Sheffield:]

No, when you move down to the southeast, you will see an EOG approach. They're announcing higher gas-oil ratio wells. It just happens to be, as you move down toward that area, it's just the vertical wells are gassier. And so you are going to get more gassy in those areas, but I don't expect it, up in this Giddings area, to change.

[Timothy L. Dove:]

I'd comment, Brian, just simply to say that it's too early to know. But if you look at vertical Spraberry history, which [indiscernible] many more zones contributing than just the Wolfcamp, you do tend to see slight increases of the GOR through time on the production of the well. We don't know whether that applies here or not, though, until we see more data.

[Brian Singer:]

And then in the Eagle Ford, since it looks like you're -- it's essentially entirely delaying, the gassy zone, the dry gas side, how should we think about what your production mix would look like in terms of what percent would come from that, from dry gas in the context of your overall guidance in, say, 2013 versus where you are right now?

[Timothy L. Dove:]

Well, if you look at our current production there, I don't have the exact number but I know that, overall, we're looking at about 40% gas in the production mix. That's drilling the liquids-rich wells. And so I think, when you then mix in about 15% natural gas drilling, dry natural gas drilling, that could go up slightly but not in a significant amount.

[Operator:]

We'll take our next question from Dan Morrison, Global Hunter.

[Daniel J. Morrison:]

I think probably everything has been asked and answered by now, but the one question I had regarding kind of expectations for the horizontal Wolfcamp performance that are baked into your outlook. I know that's going to be a moving target, but what's your, when we're thinking about your projections and guidance, what kind of rate assumptions do you have baked into your horizontal Wolfcamp well?

[Timothy L. Dove:]

Dan, again, it depends on how many wells banners [ph] are actually put on production this year. But our average we're out with now is about 2,000 BOE per day average for the year, realizing that, because we have 3 rigs running now and we will have 7 by the end of the year, it's a significantly back-weighted curve. So I think the way to think about it is we're just ramping up from with these first 2 wells having been drilled, as we add then 30 to 35 wells in terms of drilling, how many would be on production by the end of the year? I think the main message here is the bigger impact is on 2013 than it is on 2012.

[Daniel J. Morrison:]

Right, and but when we think about individual well, kind of what's your, you alluded to a type curve or your kind of standard well that these were meeting, what is your sort of your planning well...

[Timothy L. Dove:]

Well, I think it's a little bit harder to answer the question. That's why we're trying to be not very specific, Dan, because we've shown you the exact production for 2 wells, that's the limit of the data we have other than looking at offset operators' data, but I think you're going to see the natural declines on these wells. But what's interesting about the wells we drill, it's been relatively flat over the last few weeks of the production. So maybe they overperform, but we kind of have to beg off on details on that because we really need to have the data before we can give you the exact answer.

[Daniel J. Morrison:]

Or you'd just make things up. One other question about that play

[Timothy L. Dove:]

Well, I -- if Jay was here, he can answer the question, if I botch it. But the point I would make is, because I talked to the geologists about this, in the sweet spot, which is a lot of the areas we're drilling now, you have 800-foot section in this Middle and Upper Wolfcamp. And, but the Wolfcamp is so significant, so ubiquitous that, actually, as you go towards this, the edges of our field areas, you have a reduction of that thickness but it's not significant because it’s only like 700 feet. So really, you're just talking about areas or sweet spots which are associated with thicker sections, being that 800-foot section, and that correlates well to oil in play. So I think it's the fact that you're going to see this play expand from an aerial standpoint as we go forward. But right now, we're focused more on this central area where we know we have upwards of 100 million barrels of oil in place per section.

[Operator:]

We'll go next to John Herrlin with Societe Generale.

[John P. Herrlin:]

Just a quick one. With the Wolfcamp, you said in the release you were running microseismic on the horizontal wells. Do you plan to do that in every well or just until you get a good sense of what the fracture pattern should be in terms of the intervals? And how much does the microseismic cost?

[Timothy L. Dove:]

The answer to your first question is that we'll be doing sporadic microseismic as we're drilling in various areas. If you refer back to the map that's on Slide 13, you'll see there's actually 3 specific areas we're going to be drilling. And in those areas, we want to make sure we have good microseismic data in terms of the specific areas we're going to be drilling. And once you have good data to understand the frac propagation with some data points, I think we're good to go in those areas. In terms of the cost, it's about $400,000 to $500,000 per well.

[Operator:]

We'll go next to Richard Tullis with Capital One Southcoast.

[Richard M. Tullis:]

Tim, I noticed that the gas component of the Barnett Combo wells dropped, I guess, from 75% previously to about 60% now. I know you're doing the longer laterals, but what's the key driver there?

[Timothy L. Dove:]

Well, our data shows basically they’re the same from looking back through history so I'm not sure where you're getting that data point.

[Richard M. Tullis:]

I was just looking at more of the prior releases, but that's fine. I could check with Frank later on that.

[Timothy L. Dove:]

I think, for some time, we've had 42% gas in the mix and 58% liquids. And I think that's what the slides continue to show.

[Richard M. Tullis:]

And looking forward, cash flow versus CapEx beyond 2012, what are you expecting, using $100 oil, $4 gas, what are you expecting CapEx-wise to generate the growth that you're projecting out now for 2013, 2014?

[Scott D. Sheffield:]

Yes, I think the only, the 2 increases going into 2013 will be in the Eagle Ford going up to 14 rigs and also our carry will be going away in 2012. So in '13, the rig count increasing there and the carry going away will be the big increase in our CapEx. But the cash flow is expecting, it looks like, about $2.8 billion. So we'll be as close to cash flow as we can. Obviously, there will be a ramp, a continued ramp-up, adding 3 more rigs going into the horizontal Wolfcamp play. That'll be a little increase. We'll end up being very, very close to our cash flow in a $100, $4 scenario.

[Richard M. Tullis:]

Okay, and then 2014, you could be free cash flow positive?

[Scott D. Sheffield:]

Yes, going into '14 and '15, more free cash flow positive.

[Operator:]

Ladies and gentlemen, that's all the time we have today for our question-and-answer session. I'd like to turn the call now back to Scott Sheffield for closing remarks.

[Scott D. Sheffield:]

Again, thanks for being patient and listening to us during the quarter. Really, another great quarter. We're looking forward to seeing everybody on the road and some of the conferences that are coming up. Again, thanks.

[Operator:]

Ladies and gentlemen, thank you for your participation. This does conclude today's conference.