Pioneer Natural's Management Presents at Bank of America Merrill Lynch Energy Conference (Transcript)

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Pioneer Natural Resources Co. (NYSE:PXD) Bank of America Merrill Lynch Energy Conference Transcript November 21, 2013 3:35 PM ET


Frank Hopkins - Senior Vice President, Investor Relations


Doug Leggate - Bank of America Merrill Lynch

Doug Leggate - Bank of America Merrill Lynch

So, hope that, I think we are going to get back on schedule for the webcast. So thanks again for everybody being here. I think one of the more topical stories, obviously that happened in 2013 has been Pioneer Natural Resources. I think everyone is familiar without their position, so we are thrilled to have Frank Hopkins here. It's been a busy year for you, Frank.

Frank Hopkins

It has.

Doug Leggate - Bank of America Merrill Lynch

So we’d love to hear story and if you maybe go about 30 minutes then we will turn into Q&A.

Frank Hopkins

Great. Okay. Thanks. Appreciate it, Doug. I want to thank Bank of America for having us here. I think this is the third year in a row that we have done this. I find that, you look at the quality of investors that comes here both from the U.S. and international. I would tell what it is well worth our time. Again Doug thanks for your support and the support of Bank of America for Pioneer.

Let me, if I can get move this forward. As Doug said, it’s been a pretty busy year for us and I got to tell you in my working career which has been pretty long. It’s probably one of the most, if not the most exciting years I have ever had.

When you look at Pioneer and I’ll just run through a little bit of overview about Pioneer, those of you who don’t know a lot about the company. We are basically through major restructuring that we started back in 2005. We pretty much got ourselves now back to the U.S. soon just the U.S. lower 48 and our focus if you look on the bar chart on the top right is this Spraberry/Wolfcamp trend and the Eagle Ford, two of the three hottest liquids oil plays in the U.S.

We have been the best performing stock in the S&P 500 on the energy side since 2009. It’s been a great run, a lot of it, I think is the success of this restructuring that we did. We are the second largest oil producer in Texas and the key asset and what you are going to hear talk a lot about and what investors want to talk about is this horizontal program that we have got underway in the Spraberry/Wolfcamp.

Couple other things of note, we are vertically integrated. We have got pressure pumping services of about 300,000 horsepower. We are the 13th largest pressure pumper in the U.S. We have a number of other service activities which support our operations in the Eagle Ford and this Spraberry/Wolfcamp.

Take a look at our hedge position, if you are concerned about the oil prices and where they might go. Take a look at our hedge position for next year. Take a look at it for this year and the year beyond. For next year just to give you an example. We are 90% hedged on our oil production, that oil production is hedged with the flow essentially at $94.

And take a look at our gas position we are 70% hedged on our gas production and that for is about $4 in Mcf. So we feel like we are in a good position to continue our drilling program keep it going if we have a downturn in the oil prices. The other thing is look at our balance sheet. Our balance sheet is in great shape. I am going to show it you in a couple minutes and hopefully you will agree.

Now, I’d talked about exciting and what has been happened in recently. Just put forward this slide which talks about some of the things that have happened in the third quarter here and the early fourth quarter.

In the horizontal Wolfcamp Shale, in Spraberry/Wolfcamp, in the Permian Basin, Pioneer recently drilled just a couple weeks ago, put on production the best horizontal Wolfcamp Shale D interval well in the Midland Basin. I will show you some of this statistics on that in a few minutes. It’s the best IP and one of the best performing well, if not the best performing well so far that’s been drilled in the Midland Basin.

At the same time we also put on the best horizontal Wolfcamp B interval IP well in the Midland Basin. And we just really started going after the Wolfcamp B recently and you will see we have expanded that interval from what some of our peers had done on the east side of the play 60-mile to the west.

We’ve done a significant downspacing pilot in the southern Wolfcamp JV area. We have continued a successful downspacing program in the Eagle Ford where we have gone from the 1,000 feet down to 500 feet.

We completed our first successful Upper Eagle Ford Shale well and about a month or so go we announced the sale of our Alaska subsidiary, which is going to allow us to redeploy a capital from Alaska down to lower 48 and specifically to the northern Spraberry/Wolfcamp.

Really quickly our capital program, it hasn’t changed all years, it has been about $3 billion. It’s been split among the assets pretty much the way you see it there. That is funded by $2.3 billion of operating cash flow and cash on the balance sheet, which at the end of the third quarter was about $750 million.

Now, let’s take a quick look at margins. And I think you'll see pretty quickly why we are focusing more and more of our capital on the Spraberry/Wolfcamp in the Midland Basin. If you look at cash margins and this is not only -- this is basically revenues, less production costs, production taxes and G&A. All of our corporate G&A is in this number.

Our average margin and this isn’t in Pioneer's number, this is five analysts. For 2013, is little over - it looks like it's about $35 and appears on average of $34.50. Now, what's influencing that? If you look at the black on the left, that’s primarily people that have -- basically they are more liquids type companies. The red on the right is more gas type companies. And what's happening is Pioneer has a lot of legacy gas, but we've been increasing our liquids -- our liquids as you see on next chart are up over 60% of our total mix.

So take a look to the far left and look at the margins that we are generating in our horizontal drilling in the Midland Basin. At $98 crude, yeah, crude is down little bit from that number, but that’s $70 a barrel after all the cash cost were taken out. And in the southern JV area, it’s about $5 less. So these are the highest margins wells that we have and clearly some of the highest in the industry and as a result that’s where more and more our capital is going to be focused.

Looking at our growth, this is basically a slide that we had in all year. It’s very interesting because this year, we are estimating that we are going to grow at 14%. We fine tuned that number as years gone on. There is 13% to 18% CAGR, a lot of people were interested in it, on our three year growth because they know what we’ve been doing in the Midland Basin and also what we’ve been doing in the Eagle Ford.

And people are saying, alright, what that’s going to look like going forward? I think, Scott Sheffield, our CEO has been pretty transparent that we expect it to be more towards the high end and the low end of that range and the other thing that you are going to see is we will push that out beyond 2015, when we get to February and we announce our 2014 program and we’ll go beyond that.

I talked about the balance sheet, 21%, net debt-to-book capital. We’ve got a metric that our Board pays very close attention to. Our debt-to-cash flow, the max they want to cite is $1.5 billion right now or $1 billion or even below $1 billion, so lots of flexibility on the balance sheet, again, investment grades. So, flexibility, as we go forward to the extent to support -- any support that we need for our drilling program.

Look at the green on these pie charts on Slide 9. And you can see pretty quickly, it's all about the Spraberry, it’s all about the Spraberry/Wolfcamp. Not only when you look at proved reserves and where the company has been, this is our premier legacy asset but also look at the chart on the right, the pie chart and you can see all that green between vertical locations and horizontal locations. The company overall has 9 billion barrels -- over 9 billion barrels proved resource and certainly the majority of that is in the Permian.

One of the things you're going to see going forward is we’ve really ramped down our vertical program. And our vertical program over time, as long as the economics remain so much in favor of the capital efficiency of drilling horizontals, we will be out of verticals. So this chart is going to change. You are going to see a lot of that vertical resource move to horizontal. And don’t be surprised, this is based on a 140-acre spacing.

We've already begun downspacing successfully to, at least half that levels, so don't be surprised if you see this number increase as we go forward. Let’s talk about -- quickly about our southern JV area. This is an area where we have a joint venture with Sinochem. We’ve drilled 90 wells to date that were in production at the end of the third quarter, currently running about eight rigs.

We expect to spud 100 wells in 2013. The second half of this year is more focused on our northern acreage, which has the higher return area. When I talk about the northern acreage, this is the northern acreage of the southern Wolfcamp joint venture. But clearly the wells there have been better performing in the ones in the southern part of the JV area, not that the ones in the south are bad but actually, when you look at the geology it’s better in the north.

I point you to one thing before we leave this page. I talked about the best-performing Wolfcamp B well in the play in the whole Midland Basin so far. And it’s at University 2-20, which we have highlighted on the map. One of the things I also mentioned was this downspacing test we have done. Basically this year, we did a downspacing where we went from -- I’m going to round the numbers, a 120-acre spacing.

Going over, you can see the red dots down there on the schematic on the bottom, down about 80-acre spacing. Highly successful, we’ve put 12 wells on production. They all came on about 1,000 barrels a day.

Next year, we are watching this. We’ll see what kind of results we get but the expectation is that we will try to take the downspacing further. It says 50 acres here, it could end up being something like 40 acres.

So -- and the thing that’s nice about this is we are learning in the Southern JV. Southern JV here is about a year, maybe year and a half ahead of what we’re doing in the north. So a lot of the things that we’re learning in the south will be translated directly because the geology is the same into the north.

Next year, real quick we’re going to continue running eight horizontal rigs. It’s going to be about 115 wells next year. We’re going to continue to drill on three well pads mostly. I think the key thing next year is that we've already been increasing the lateral lines down there. If we go back two years, when we started drilling, we were around 7,000 feet. We moved to 8,300 feet this year and next year, we’re going to push it up 9,400 feet, which means we’re going to be drilling lots of 10,000 foot laterals, where we have lease line capability.

Okay. What are we doing in the north? This year has basically been a delineation appraisal of our horizontal potentially in the north. Basically we’re going after six intervals here. You can read them across the top, Wolfcamp D, B and A, and the Middle Spraberry shale, Jo Mill shale and lower Spraberry shale. By the end of this year, we will have spud 19 Wolfcamp wells and 15 what we call Spraberry shale wells, which includes the Jo Mill.

What do the results look like? Let's look at the Wolfcamp D wells first. Again I point out that well at the top, the Wolfcamp D in Andrews County, the University 7-43. Best IP and that’s the one I mentioned at the beginning of any interval in the north.

And you can see our other three wells that we brought on production. We got four D wells on production right now. You can see that they’ve got a fairly steep decline early days but they flatten out pretty quickly get on the curve and it's too early to make call on what the EURs are. We just don't have an update yet, as you can see, the longest ones only been run about 75 days.

I think the thing that’s happening here is a lot of our peers have drilled Wolfcamp D wells to the Hearst. And based on the kind of results, they are seeing, 607,000 barrel EURs with much longer production history. I think it's fair to say that our confidence level is pretty high and early results here that we’ll be able match those or perhaps even do better.

Here's a map of where these wells are. This is Slide 15. You can see Apache and Laredo and the success they've had on the Eastern side particularly over Glasscock County. Our Wells are 60 miles to the west and north. And to the south, so far we’ve gone 30 miles to the west. So as you can see, the area of extent here of the potential is really high. And I would tell you and the people that follow the story pretty well and know what we’re doing.

I know that we got a very strong geoscience team. There's been a big geoscience effort and we have all these intervals mapped. And we can tell you that the play between where Laredo, Apache and some others are drilling in the east, compared to the west. It’s very ubiquitous across that whole area. So matter of act, it’s ubiquitous for the A, the B, the D, the Spraberry shales because this is the heart of the Midland basin. This is back in Pennsylvania edge.

This is where all the good organic material got deposited in a very quiet low basin. Now what about Pioneer’s A and B Wells. Well, here you go, here is the -- let say six wells so far. We’ve got our own production. Again, there is a B well that’s the best well that’s been put on production anywhere on the northern acreage.

You can see the longest wells are now been on production almost 270 days. It's basically tracking 1 million barrel type curve. I think if you look at the well so far, I think the confidence level is pretty high that we think on average as we go forward. These wells look lie they were will be at least 800,000 barrels.

Now let’s look around the area because lot of people say, well, great you guys have built -- you guys have drilled some of theses vessels, maybe we’re just picking sweet spots. But I encourage you to look at where we have drilled on this map. I’m not going to go through each player and each of our peers and what they drilled.

But you can see, there is wells to the west, wells to the east, wells to the south, wells to the north. So lot of wells are getting drilled and one of the things that’s happening is it’s helping us prove up that what our geoscience team is saying is it’s absolutely coming to fruition.

What kind of returns do you get on these wells? Well, you can drill 800,000 barrels horizontals for $95 oil and $8 million you can get 125%. You can get 150% if there are million barrel wells but the point is even it’s -- even if there are 650,000 at $8 million, you’ve got 60% returns.

So I think what's important here is notice those payout years because if you can drill wells, there are 8,000 barrels EURs or above, there are going to be payouts in less than a year. Basically you can put together much of your program that will be self funded. And so this is the thing that you’re going to see us look to do as we go forward, that has begin to high-grade and as we do more delineation really decide what we should go after. We’ll talk about that in just a minute.

Here is the activity chart, it’s the map and I am not going to go through all the details other then telling you in the north now, we have got 16 wells on production, four are currently flowing back, we got another four wells waiting completion and we have got five rigs running. So the majority of these wells this year are being completed and -- drilled and completed on two well pads.

Now what about next year? Well, couple of weeks ago, four weeks ago, we were planning to go from five to eight rigs then we announced we are going to sell Alaska, we said we go to 10 rigs.

Last week, after some internal discussions and looking at the opportunity set in front of us and looking at our capital funding availability next year, we are going to push that 10 higher.

Now I am not going to tell you that number yet because it’s not set. Actually our Board is having discussions on that probably as we speak this afternoon sort of first a pass and to get their thoughts on it. But, clearly, that plus is going to come to fruition it just a matter of how many that’s going to be.

We have got 15 vertical rigs running next year that’s to meet continuous drilling provisions next year. The expectation is that that will be 12 or less. We are going to three wells pads in the north, I mentioned two well pads this year, so we go to three wells next year experience in the Wolfcamp, southern Wolfcamp JV area and Eagle Ford says that’s probably the best way to go.

90% of our program next year based on where we are, what we know about the Wolfcamp versus the Spraberry says that we will basically have a program that’s 90% Wolfcamp, A, B and D wells.

This year we had $80 million of science and infrastructure costs. I don’t know what that new number is yet because our program is evolving, as I said, we just decided to add rigs, but I can tell you we will not do as much science this year, we won’t have to, thanks to the good work we’ve done and also some data trades we have done with some of our peers.

Our drilling times are coming down and one thing that’s happened, again those of you who had followed us on these two well pads, it has been 120 to 150 days to get two wells on production because we are doing science on these wells. We take the science out and we go to three well pads, we get three wells on in about 145 days. That brings your average per day to get wells on production down from 65 days to 50 days.

Here is just the growth profile this year. We are looking at 21% to 22% over where we were in 2012, that’s off a significant growth from 2011 to 2012 that was driven by primarily vertical drilling, if you go back to 2010 to 2011, you see the same kind of growth. So the track record is there.

Now one thing I would point out, lot of people ask us, what’s going to happen to your vertical production, so you can see that dark green vertical production is the main component of our production today as we evolve the horizontal and with 15 rigs running that declines about 10% a year, if we get out to let’s say 10, 11, 12, you are probably going to be closer to 15% decline on an annualized basis.

Now, let’s not forget about the Eagle Ford, because the Eagle Ford is really doing great work. Now lot of the work they are doing is already translating into what’s happening in the Wolfcamp.

With our culture, we are incented to share information, share learnings. And if you look, we -- this is a slide, it has been out there but back in 2012 we started downspacing from basically, I call it 120 acres to 60 acre spacing between wells and that was basically in our liquids rich areas. And as a result of that successful downspacing that added about 300 locations in our liquids rich areas and those are the ones that are highlighted on the map.

Now, what we have done is, we have gone further and we have tested 50 -- over 50 wells now on three-well and four-well pads using zipper fracs. And what has happened is the -- what’s the average EUR for the zipper frac wells on these pads has increased EURs from 1.2 million barrels of oil to 1 million -- from 1 million barrels of oil.

Where we are going from here? Well, if you look at downspacing test, we are now going to move further down. We are going to move to 3 -- something like 300 feet, so maybe you are down to 40 or 50 acres, we will see how that shakes out. But we have recently drilled a successful Upper Eagle Ford Shale well and as you can see on the diagram kind of in the middle of that chart, we are now going to do these down spacing with staggered wells in the upper and lower Eagle Ford shale and hopefully that will have success and if it does that could probably in our liquids rich areas and other 300 to 400 incremental locations.

Here is the Eagle Ford growth profile. Again, back in 2011, we were 12,000 barrels a day and this is only one-third of the production we are actually producing. We have got Reliance is our partner down there and then we have got a Mexican company called Newpek which has a small share. So this is roughly about a third after royalties, this is net.

As you can see we grew it from 12,000 to 28,000 barrels a day in 2013. We are looking at 34% to 38%. I will highlight because some of you probably notice that we dropped from 38,000 to 35,000 barrels a day in the third quarter. Basically, what happened was we moved to pad drilling in a big way in the third quarter. We started drilling bigger pads and the bottom line was that we ended up not getting the wells on quite as quickly as we thought we would. We were -- just basically too aggressive in our forecast but I can assure you that 39 or 41 we are well on the way back, we are actually above where we were in the second quarter right now.

So, anyway, hopefully you’ve got the message that we are U.S.-centered company. Oil is what our resource base is built on. This Spraberry/Wolfcamp Shale horizontal potential is significant. Eagle Ford Shale still has a lot of running room.

Our growth profile is going to be strong going forward and don’t miss the fact that we have got some good cost protection in place through vertical integration and revenue production through our derivatives. And as I said, our balance sheet is always there if we need to use it. Doug, that’s it.

Question-and-Answer Session

Doug Leggate - Bank of America Merrill Lynch

Thank you, Frank. (Inaudible)

Frank Hopkins

Can I come over there and sit with you?

Doug Leggate - Bank of America Merrill Lynch


Frank Hopkins

Yes. Well, where we are is we were -- we are kind of in, we are in transition, meaning we are coming out of ’13 and into ’14 and we are developing our program as we speak. That growth profile for 2013 and three years going forward, was put together back in literally at this time last year when we put our capital program together.

We hadn’t drilled a horizontal well in the north at that time. We had a number of them in the south and in the south our confidence level was growing at 575,000 barrels was probably a good average type curve and in fact its proven to be right on the money based on the continue drilling program this year.

Where we are now is when you look at the results and you saw, Doug, just mentioned and now you are drilling these A and B intervals at 800,000 plus. Certainly, the D’s look like they can be north of 500,000. So as we go forward this year, our program is going to be very much influenced by these higher EURs and the growth rate that we put forward from there.

So as I mentioned, Scott, has single, look for a number that is closer to the higher end of that 13% to 18% range for the next three years going forward. We are working that through right now.

As I said, right now, our rig count just moved twice in the last two weeks. Obviously for the good and has the potential to push it up. I won’t caveat and I only throw this out because you’ll hear us talk about it. We only have in north right now five rigs running.

There are seven rigs running in -- we had seven now we’ve just gone to eight. But when you move to pad drilling and you saw it in Eagle Ford, production gets -- I hate to use the word lumpy, but that's the best word I can describe it in my friend’s zone both the sell side and the buy side, don't have a better term for it. But you will have lumpy production, as you go forward until you build up this base of horizontal rigs and get the production line.

So, I would tell you that probably the outlook early in the year will be remember rolling five rigs right now, we’re going to go up to 10. But if you think about those 10, even if there all on January 1st, I’m not going to see any production from those rigs probably until 120 days after. So all of a sudden, I’m in the second quarter. So just be patient with us, give us time to ramp this thing. It’s a same thing that happened this year.

We have one rig running through May and now we’re up to five and we’re running five and the five are now are fully integrated and bringing the wells on just as we thought in this 120 to 150 day window.

Doug Leggate - Bank of America Merrill Lynch


Frank Hopkins

That’s funny you bring that up because you asked me how my one-on-ones were going on and I said I had a really good day at one on ones and one other questions, we got to ask the most was are you going to extend a three-year growth rate to five years. So at least some people were interested in what it looks like. And I told them, I said, directionally the five-year number -- the five year CAGRs probably going to be very similar to the three year based on the inventory we’ve got.

But here is what where we’ve been and I think it’s evolving right now. We have stated earlier this year, I think even back as early as April that we hoped to get to 25 rigs in the north and 25 rigs in the south by 2018. And that was basically ramping up three to four rigs per year in each area. And I granted some year it might be three, some might be five but that was kind of what we’re looking at.

But I think, directionally with what you see happening in the north already. If we’re 10 plus, I think, the logical conclusion would be, they are going to be somewhere in the teams already and it's only 2014. So I would say particularly for the north, I think, 25 was a nice number to have out there, But I think, clearly the potential by the time we get to 2018, that number will be higher. Now again it goes without saying, I've probably don't have to say it but that assumes that oil prices and commodity prices co-operate.

Doug Leggate - Bank of America Merrill Lynch

Any questions from the floor? (Inaudible).

Frank Hopkins

It’s not like you, Doug.

Doug Leggate - Bank of America Merrill Lynch


Frank Hopkins

Yes, that’s a good question. I think right now and I'm going to dodge the specific answer because we really don't know. We’re in the high-grading process right now, as I mentioned, we’re delineating -- we’re still delineating and appraising our acreage. For example, I mean, you saw the successful Wolfcamp A, Wolfcamp B, Wolfcamp D results that we’ve had. I mean very clearly that sort of the bars has been set, particularly with the As and Bs, but the Ds are looking pretty good, so you got a high bar.

Now you’ve got coming behind that the Spraberry Shales and the Jo mill Shale wells. We got four of those that are basically cleaning up the watering as we speak. Those Wells because there are shower, they are not as high pressure as the deeper well. So they take longer to unload. So when you start to look at those wells, you say to yourself, well, are they going to be able to compete or not. First off, it’s going to take 30 to 60 days to get them on production as opposed to the A, Bs and Ds appear to get up the IP in a matter of just a couple of days.

So you begin to look at that, now there likely going to be little cheaper to drill because there are shallower. So then you start to say all right, well, they are cheaper, may be they take longer to come on. But what are the EURs going to be. You look at some of the early results that we’ve had. We drilled two Jo Mill wells in -- basically when I say the JV area, it’s not part of the JV but is down in that area, the JV is only Wolfcamp intervals.

But we look at two of the Jo Mill wells that we drilled. We look at a couple of other players of the rising star, for example a private companies, it’s on our slide as put out some really good Spraberry shale wells. So you say well can they compete or not? And we don't know yet. We got to get the results. We’ve got to get them on.

So once we go through this high-grading then, you'll see us take a good hard look -- alright, there’s going to be an opportunity, which you just not going to be able to get to for a lot of years. And so how do you monetize that, do we -- is there some fringe acreage that we just let go and so?

How do we -- if we decide that we don’t want to drill one or two intervals? Is there a practical way to bring somebody in to drill those intervals, recognizing you are on the surface and now you got two companies on the same lease drilling different intervals and you need different infrastructure above ground? It becomes complex and so that’s why I’m saying, I’m going to dodge because I don’t know yet. But it is clearly something I assure you that we will address once we get a better handle on -- when we high graded, we figure out really what we want to go after early and what really gets pushback in the inventory chain.

Doug Leggate - Bank of America Merrill Lynch

Just a quick question. You drilled wells, 65 wells (inaudible)

Frank Hopkins

Yeah. It’s interesting because not only I mentioned about some data sharing, but it’s not only what we’ve drilled, but it is sort of what others have drilled. And for instance, let's talk about the Wolfcamp A and Wolfcamp B. First off, it's important to note and I think I said it, that our geoscience team has mapped all of these intervals and there is a slide in the backup, which shows, for instance the Wolfcamp B Tier 1 versus Tier 2. And that Tier 1 acreage is all based on four geologic maps that have been created by our geos and have parameters that says, look, to make a really good well, these are the cutoffs that you need and you take all those cutoffs and you stack them up and you figure out, alright, this areas is the best, this area may not be as good. It maybe good but it may not be as good.

So where we are with that, is you take those maps and then you look at the Wolfcamp B. Let's start with the B and the A. And those two -- the oil in place is actually a little bit higher than the A. But you look at that geology between the two and you can hardly tell the difference. And so you start to say, alright, where have you drilled wells, where have we drilled wells? We just drilled a well in the northern part of Morgan County. And we’ve drilled wells, really good wells down in the northern part of Upton and Reagan counties.

And we’ve drilled wells in between, a Diamondback and RSP have drilled really good wells to the west and Laredo has drilled really good wells to the east. And I look at this geomaps and I’m going, as far as we are concerned it’s essentially all proved down through that area. The Wolfcamp D, it's pretty similar. Again, we just drilled the wells out to the west. They were just a -- of course, we just drilled the Wolfcamp D well up in the University area.

So it’s the same kind of thing where your confidence levels pretty high. We didn’t have the geoscience. I think that's the one thing and always put a plug-in for our geoscientists and our engineers, because these guys have really identified the opportunity here and it's interesting because we will go to them and we will ask them, how is a well in this area going to be performed? And I’m going to tell you, they can't tell you what the IPs going to be, but they will tell you. You can get a strong well here or you are not. I will give you a case in point -- our southern JV area.

As I said, the northern part of that is better than the south. We drilled some of early wells down there. They were very clear and we were drilling, particularly the whole acreage back at that time on University lands. They came to us and said look, these wells are going to be good but they're not going to be as good some of the other ones that we've already drilled. And so their track record I would say is pretty strong for identifying it. And that’s what gives us the confidence. The Spraberry Shales, they are all mapped. It all looks like it should work, but that’s why you have got to drill some more wells.

Doug Leggate - Bank of America Merrill Lynch


Frank Hopkins

Well, I would tell you this, it's no secret. We press released it last year that we were going to sell the Barnett, that transaction did not come about because, basically we did not get an offer that we felt was satisfactory. And so we decided for the time being that we would keep that asset and we will continue with a two rig drilling program there. I would tell you, it's probably down the road, if someone were to commit and make an offer better than what we had before I think -- obviously we’ll consider it. So we just have to see but clearly that is viewed as non-core.

Eagle Ford, we get the questions. We got it even more today after the GeoSouthern deal. But I would tell you GeoSouthern is literally -- they are our neighbors. They are into Dewitt County. They've got some of the same grade acreage that we have. And that's why they’ve got a good price. But I would tell you -- you saw the downspacing that we’re doing there, we are not done even evaluating the play yet.

I think it would be premature for us to even think about selling it. It’s got a growth profile that’s pretty attractive through the end of the decade. So, I would, never say never, but at this stage I think it's fair to say that’s a core asset and we are keeping it and we’ve got some pretty significant growth. That’s going to come along with it.

Doug Leggate - Bank of America Merrill Lynch

We pretty much appreciate that.

Frank Hopkins

Well, thanks. I’m glad I could make it.

Doug Leggate - Bank of America Merrill Lynch

Thanks a lot.

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