先鋒自然資源 (PXD) 2014 Q1 法說會逐字稿

Welcome to Pioneer Natural Resources' first-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 earnings and webcasts.

This call is being recorded. A replay of the call will be archived on the internet site through June 1.

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 made 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, Frank Hopkins. Please go ahead, sir.

Thank you, Leah. And good day, everyone. Thanks for joining us. I'm going to briefly review the agenda for today's call. Scott's going to be up first. He'll provide the financial and operating highlights for the first quarter of 2014 -- another great quarter for Pioneer. He'll then discuss our capital program for the year, our production growth forecast through 2018, and our substantial resource base, which is concentrated in two of the largest shale oil plays in the US, the Spraberry/Wolfcamp and the Eagle Ford Shale.

After Scott concludes his remarks, Tim will review our recent horizontal drilling results in the northern Spraberry/Wolfcamp, and the drilling plans there for this year. He'll also comment on drilling plans in the Southern Wolfcamp joint venture area and the Eagle Ford Shale. Rich will then cover the first quarter financials in more detail, and he'll provide earnings guidance for the second quarter.

And after that, we'll open up the call for your questions. So Scott, I'll turn the call over to you.

Thank you, Frank.

Good morning. Again, as Frank said, another great quarter for Pioneer. First-quarter adjusted income of $183 million or $1.26 per diluted share. First-quarter production, 172,000 barrels of oil equivalent per day from continuing operations. That does reflect Alaskan Barnett Shale as discontinued ops.

Obviously, that was above the first-quarter production guidance range of 166 MBOEPD to 171 MBOEPD. We're up 8,000 barrels a day from fourth-quarter 2013, 5%. Oil production was up 9% on the same quarter. The growth being driven primarily by the horizontal programs in both Spraberry/Wolfcamp and the Eagle Ford, and the full recovery of the fourth-quarter weather-related production curtailments.

We're continuing to have the same forecast for 2014, from continuing operations of 14% to 19%, based on our $3 billion drilling capital budget. The key driver again is the northern Spraberry/Wolfcamp, where if you remember, we were at 5 rigs a year in 2013, added 11 rigs, all during the first quarter. We have 16 rigs up and running, drilling mostly 3-well pads.

It does take somewhere between 140 to 150 days to see first production from a typical 3-well pad. That's why we'll talk later about the big impact of second-half production and with the POP schedule we'll show in a few seconds.

We'll be increasing our wells. We're putting on production from 125 wells for the first half to 175 wells in the second half. Obviously, that increase is primarily driven by the northern Spraberry/Wolfcamp.

Slide number 4, we did close the sale of Alaska subsidiary in April, continue to pursue the sale of Barnett Shale assets. In addition, we extended our Atlas gas processing agreement, where we owned 27% of several plants in the Spraberry/Wolfcamp area, for 10 years to 2032, to really ensure long-term capacity as drilling activity continues to grow.

We're adding 400 million MMCFPD a day of new capacity coming online by second half of 2015. The first of those plants is coming on fourth quarter in 2014, with the second plant second-half of 2015.

We got coverage with our derivatives of 90% of 2014 oil production at $93 a barrel. We do have upside with those three-way callers of up to $114 a barrel for WTI. 80% of the production is protected against volatility in the Midland-Cushing oil price differential, which is running today about $7.50 to $8. We only have about 20% exposed to that number. The rest of our oil is priced either off Cushing or off LLS in the Gulf Coast. Strong balance sheet, with $260 million in cash on hand at first quarter, net debt-to-book of 27%.

Going to slide number 5 on drilling highlights, again, we've updated the type curves Tim will go over. But our production data from 17 Wolfcamp A, B and D wells, 6 Lower Spraberry Shale wells continue to support our strong EURs that we have shown over the last several months. We are increasing the high-end of the Lower Spraberry Shale EURs from 800,000 barrels of oil equivalent to 1 million barrels of oil equivalent.

When Tim goes over the type curves, you can see we have several wells that are at least 1 million or exceeding 1 million barrels of oil equivalent on a normalized 7,000-foot lateral. Again, a breakdown -- I won't go into details on the table, but the big change is increasing our Lower Spraberry from 575 million barrels of oil equivalent to 1 million barrels of oil equivalent, with returns of roughly 45% at the low end to over 100%-plus returns on the high end.

We continue to see the same type returns on the Wolfcamp A, the B, and the D. We are increasing our activity in the Lower Spraberry Shales, up from roughly the 10%, up closer to 15% for the rest of the year.

We're placing our first key Jo Mill Shale well and our first Middle Spraberry Shale well on production. If you remember, we did have prior issues with our prior Jo Mill Shale wells, but this is our first good completion on a Jo Mill Shale well. Both are tracking Lower Spraberry Shale wells when you normalize to 7,000 feet. So very excited about both of those results.

Going to the Eagle Ford, we have 12 Upper Eagle Ford wells placed on production through mid-April. As part of our continued down-spacing and staggered program, results continue to be very, very encouraging. In addition, we're going to a 2-string design instead of a 3-string design. It's saving us somewhere between $750,000 to $1 million per well.

Going to slide number 6 on capital spending, we're leaving our capital program of $3.3 billion, with $3 billion to drilling capital -- pretty much same breakdown we've been using since we've announced our capital program. Obviously, with higher prices the first four or five months of the year, we have cash flow up to about $2.5 billion now. With cash on hand, proceeds from divestitures, we have plenty of financial flexibility and fire power to continue to accelerate drilling activity.

Slide number 7, in regard to production growth. We're still targeting 16% to 21% compounded annual production growth for the three-year period from 2014 to 2016. You can see for the year 2014 we're at 14% to 19%. You can see also on this for second quarter, our guidance range is 173 MBOEPD to 178 MBOEPD. And then obviously, again, emphasizing back-half loaded due to adding 11 rigs in the north for first quarter. We're jumping up third to fourth quarter on average, 195,000 barrels to 210,000 barrels a day. So you can see, that's the result of increasing the number of completions in the north.

Long-term, we expect to add at least 5-plus rigs per year in a strip price environment. And in a $95 oil flat environment, we'll be adding 10-plus rigs per year, long-term. Again, we expect production to more than double by 2018, as compared to 2013 production.

Going to slide number 8, just to emphasize the fact that we're second-half loaded, we have a POP schedule on the number of wells from each of our three key areas, the Eagle Ford, the Southern Wolfcamp program and then the Northern program. As you can see, the significant increase from the 11 additional rigs that we added first quarter. We will be adding 50 completions in the north, which will significantly get the POPs up to 175 from an average of 125 for the first half of the year.

And you can see, our second-quarter guidance, as I mentioned in the earlier slide, of 173 MBOEPD to 178 MBOEPD, again, is conservative. It's also -- you can see at the POP schedule, we're adding 65 wells in the second quarter, as compared to 60 wells in the first quarter. I'm going to now turn to it over -- no, I got one more slide, sorry.

Obviously, as Frank mentioned, we said US we have probably -- what's nice is we have the largest -- we have a great inventory of over 20,000 locations in the largest field in North America in the Spraberry/Wolfcamp. Again, we're excited that we've got a great position that's going to drive the Company, obviously, for decades forward.

Let me turn it over to Tim.

Thanks, Scott.

And of course, that last slide was about resource potential. But in the first quarter of 2014, we made substantial inroads in the transition from a resource capture mode to one of execution of a ramped-up drilling campaign that's focused on production and cash flow growth.

On slide 10 is a recap of what we've accomplished so far in 2013 and 2014 in the north. It shows that we've -- as Scott has already mentioned -- placed 23 wells on production during 2013 and through the end of the first quarter.

You can really see on the map that our well control in the north is getting much more dense, having now popped those 23 wells in various zones through the first quarter, and they are shown in the table to the left. What you will see as you look back through our production data is that our production is proving to be more predictable in these areas, as further wells are drilled and more data is accumulated. And those data definitely support strong EURs and returns in this area.

As Scott mentioned, we did place one of our better completed Jo Mill well shales on, and the first of the Middle Spraberry Shales on production, and we'll show more about that shortly. The early performance looks very good, and I'll show you a slide on that in a couple of minutes.

Turning to slide 11. Actually, the next three slides are similar to those from the last quarter and have been updated with recent production results from the various zones. And in this particular slide, slide 11, it's the first six Wolfcamp A and B wells. And you can see really very consistent results.

What we've done here is essentially add another month or so of production data from our recent IR materials. And you'll notice that the wells continue to be very consistent. In fact, if you take a look, as an example here of our DL Hutt well -- made 7,400-foot laterals; it�s made 217,000 BOE in just over a year. That's comparable, of course, to our old vertical drilling, which would make something like 140,000 barrels in 40 years. Just gives you the idea of the capital efficiency of our horizontal campaign.

But all this data continues to point to excellent production EURs and production from these wells. These are actually our first 6 wells. Of course, we have put 7 subsequent wells online.

And all the wells do point to about, in the case of 7,000-foot laterals, about 1 million BOE for Wolfcamp B in Midland County and about 800,000 BOEs for Wolfcamp A in Midland County and Wolfcamp B in Martin County. So really quite outstanding results. And I think more importantly, consistent results and predictable results for the Wolfcamp B and the Wolfcamp A.

Turning now to slide 12, this is similar data as is been represented on the prior slide, but in this case, for the Wolfcamp D wells, another month or so of data. They exhibit a similar pattern of consistency when it comes to production.

It leads us to the view that the D wells continue to show support for EURs in the 650,000 BOE to 800,000 BOE range for Midland, Martin and Andrews Counties, if you assume a 7,000-foot lateral. One note, though, if you take a look at the E.T. O'Daniel well, that well, at a little over 9,100-feet lateral, is clearly well over an 800,000-BOE well.

Turning now to slide 13. And here, in this case, I'm turning to the Lower Spraberry Shale well results. You'll notice that the pattern of early production in the Lower Spraberry Shale is very different from the Wolfcamp, owing to the fact the Lower Spraberry Shale is shallower and lower pressure and it just takes a while for the load water to be produced, and for oil rates to increase.

That said [it's here that], of all the wells that are shown -- the 5 wells -- 3 of these wells are exhibiting EUR potential over 1 million BOE. And this is what has led us to, what Scott had mentioned, the increase to the top-end of the EUR range for these Lower Spraberry Shales to 1 million barrels BOE, where it had been about 800,000 barrels. And that makes some sense, considering these results are really not unexpected. Because the Lower Spraberry Shale calculates to have the highest oil in place in all of these Spraberry and Wolfcamp intervals.

We still believe that the production data for this, that we've seen the wells on this side, plus additional wells, suggests a range for Lower Spraberry Shale of being 7,000 -- for 7,000-foot laterals, 575,000 BOE to 1 million BOE now at the top-end of the range.

Turning now to slide 14, this is production data from the recent Middle Spraberry Shale and Jo Mill wells that we've been talking about. The results on slide 13 are also superimposed, so we can compare how the Middle Spraberry Shale and Jo Mill wells look versus the Lower Spraberry Shale results I just covered.

You have to look a little bit carefully here, because there's 2 wells shown. The red well is the Jo Mill well, Martin County. The black well is a Middle Spraberry Shale in Midland County. Suffice it to say it's early days in the sense of the production of these wells. But very importantly, they show a similar trajectory in their early days as they de-water, as compared to the Lower Spraberry Shale.

So we're encouraged by that, definitely, and to the fact that these wells seem to be tracking Lower Spraberry Shale wells, which have been among our best. We will continue to watch these wells to see how they compare with the Lower Spraberry Shale and the other zones.

Going to slide 15, with the types of production profiles I've just shown you, it's not surprising that the returns would be very high on this drilling campaign, as the payouts would be very fast. And you see that in the bar charts. This was actually shown in Scott's earlier data. The green shows BTAX IRRs for the various zones. We believe that the returns are definitely going to be strong in this campaign, and the data certainly suggests that. You also see on the bottom left that we have increased the Lower Spraberry Shale top-end EUR to 1 million BOE.

Turning to slide 16, and now we're really talking about what is happening, in terms of this year's program in the north. An update here. It shows that we really are in the process in the north of an early stage of adjusting to more of a horizontal development campaign, as opposed to appraisal. This gets back to the idea of executing now on more of a development campaign focused on production growth and cash flow growth.

As Scott already told you, we now are at 16 rigs. That was the planned number. That will allow us to drill about 140 horizontal wells this year. 85% will be in the Wolfcamp A, B and D. With the results we've seen so far from the Spraberry shales, we've now upped the number of wells we'll drill in the Spraberry shales to 15%. It had been 10%. But with the results we've seen, the successes both in the Lower Spraberry Shale and the Middle Spraberry Shale, we think the right thing to do is allocate some more capital to these zones.

Most of the drilling will be on 3-well pads. It pushes your spud to POP times out to 145 days, the result of which is a combination of pad drilling and adding rigs later in the year will be a second-half weighted production growth profile.

Horizontal costs in the north, generally $8.5 million to $9 million. We're now at about 8,200-foot average lateral. We continue to operate 11 vertical rigs. They are going to drill about 200 wells this year that are needed to meet continuous drilling obligations, so as to preserve our lease hold. Clearly, we'll be reducing our vertical rig count in the next several years, as the rig count is increased from the horizontal perspective.

I would point out that the photo is a pretty impressive photo at the bottom of slide 16. This is 4 rigs lined up in the Hutt lease in Midland County, banging out development-style wells. So that's a pretty impressive photo. We have a city on the ground there in Midland County.

On slide 17, now turning to the southern JV area. We are also continually focused here, just as we are in the north, on development, growing production through development drilling. Here we'll drill 115 or so wells, and longer laterals on average at about 9,400 feet, and similar in terms of the fact that most of the wells we utilize 3-well pads.

We are now in the process of reducing our spud to POP cycle time by a few days. This is the result of SIMOPs, simultaneously putting wells on production, while at the same time drilling out plugs on offset wells. So if we have 2 work-over rigs out there and several wells to operate on, on the location, it could save us up to eight days. And time is money, of course, when it comes to getting these wells on production.

We still are unchanged in the sense of the well mix, about two-thirds Wolfcamp B, with the remainder being the other Wolfcamp zones. But they are going to be focusing mostly on the northern areas, where the returns are higher. About $8 million a well. So we're pleased to report that the JV with Sinochem is going exceptionally well here in the South.

On slide 18 then, wanted to give you just a little bit of data on some other southern-area wells. We thought we would update you on somehow -- as some of the older wells are performing. You'll see the two original Giddings wells here. These are Wolfcamp B wells, having now been on production for about 2 1/4 years, and they have been phenomenal wells, at only 5,300-foot laterals.

They are tremendous wells. They are going to look like 725,000 BOE EURs. Of course, if we were at 700,000 feet, that would be about 950,000 BOEs. So it gives you an idea on our two most elderly wells, if you want to put it that way, really show consistent performance, and they're really holding up to the curves to show strong EURs.

On slide 19, Scott already covered this to some extent, but we're pleased to announce that we've extended our agreement with Atlas in the Midland Basin for another 10 years. The coverage area is shown actually on the map to the left here. It's been extended into Andrews County, and of course, a portion of Martin County.

You'll note that there's an area of Martin County that's not covered by this particular coverage area. But the balance of Martin County is an area where we have another 30% interest, and another third-party plant that's also in the process of expansion.

But as it relates to the Atlas area, capacity will increase from about 455 million cubic feet a day to about 855 million by the second half of next year. And the principal drivers of that are the Edward plant shown on the map in the south. That's a 200-million cubic feet a day plant that should come on in the fourth quarter. And another plant in the north to deal with Martin County and Andrews County production. Another 200-million cubic feet a day. We still retain about 27% of the interest in those plants.

Our production only makes up about a third of the gas processed, which gives you an idea that we're not the only operator growing production in the Permian Basin and the Midland Basin. But there's substantial other new production coming online, which means we'll need to stay ahead of longer-term bottlenecks and short-term bottlenecks when it comes to moving production.

But we think it's pretty clear at this point that another 200-million cubic feet a day plant will be required, basically, every year, as we and the rest of the industry cranks up the drilling campaign. So, the Atlas extension is really a part of our continuing efforts to be forward-looking to avoid bottlenecks in terms of processing.

On slide 20 then, and as expected after all this effort, it should be culminating in an increase in production, a ramp-up of production. And the Permian is certainly delivering on that front.

You see production having increased to 86,000 BOE compared to 79,000 BOE last year, and 80,000 BOE in the fourth quarter. We've put 56 wells on production across the basin in the first quarter. Sorry -- 28 wells on production, having drilled 56.

Looking forward, we're going to be drilling a total of 255 horizontal wells combined in both the north and the south -- again, utilizing 3-well pads. And the POP schedule, as Scott has already alluded to, is very significantly back-half weighted. We are growing horizontal production as we speak. On a net basis, it grew 4,000 barrels a day over the last quarter.

Now turning to the Eagle Ford Shale, slide 21, we're still getting very encouraging results on the Upper Eagle Ford Shale testing. In fact, we put 12 Upper Eagle Ford Shale wells on production through the mid-part of April. The results look quite excellent.

We'll be drilling another 45 Upper Eagle Ford Shale wells this year as a part of what we had discussed last quarter of down-spacing, staggering effort to move the spacing down from an original, say, 1,000 feet to 500 feet, now even to a lower range of 175 to 300 feet. And staggering between the lower and the upper intervals. Average lateral length this year is up to about 6,100 feet compared to about 5,000 last year. About 25% of our acreage is prospective for that upper zone.

Turning now to slide 22. We were seeing record production being set by Eagle Ford quite regularly. We've seen a substantial increase in the first quarter to about 43,000 BOE per day from 38,000 BOE last year, and 40,000 BOE in the fourth quarter.

We drilled about 34 wells, put 32 on production. We have 110 wells scheduled this year. It's going to be the basis of 3- and 4-well pads in this case, which, again, pushes out your spud to POP timing.

We are now utilizing for about 80% of our wells, in the first quarter particularly, two-string casing design, instead of a three-string design. Essentially, it saves you days and of course, casing, in terms of cost savings. We calculated it saves about seven days. So we can be on the well an average of 22 days instead of 29 days by taking out one of the intermediate strings. And importantly, the net cost reduction is about $750,000 to $1 million per well.

We, more in detail, covered in our fourth-quarter calls our down-spacing and optimization. But we continue to see tremendous benefits. Probably EUR increases in the neighborhood of 20% to 30%, with very little capital. Combination of down-spacing and staggering, I mentioned earlier. But in the case of completion optimization, things like pumping more proppant, pumping more high-rate fluids, and altering the stages in our cluster spacing. They are all generating tremendous returns with very little capital.

So I'm going to stop there. And I could just simply say in summary, from an operations perspective, we're executing at a high level in the midst of a rapid acceleration in terms of drilling, particularly in the north part of the Spraberry/Wolfcamp area.

And with that, I'm going to pass it over to Rich. He can discuss the first-quarter financials and the second-quarter outlook.

Great, thanks, Tim. Good morning. I'm going to start on slide 23, where we show net income attributable to common stockholders of $123 million or $0.85 per diluted share. That did include mark-to-market derivative losses of $55 million or $0.38 per diluted shares.

And then a couple unusual items -- one associated with discontinued operations, and the other of a tax benefit related to our Premier Silica acquisition a couple years ago. So adjusting for those items, we are at $183 million or $1.26 per diluted share for the quarter.

Looking at the bottom of page 23, where we show first-quarter guidance relative to our results, you'll see we had an excellent quarter, as Scott and Tim both mentioned, with the results within guidance or on the positive side of guidance. Other than mainly G&A, which was above guidance, primarily due to just people-related costs that were incurred to support our growth initiatives as we moved throughout the year.

Turning to slide 24 on price realizations, you see another good quarter in terms of pricing. Oil was up 2% to $92.38 per barrel. NGLs were up 9%, principally related to the strong propane prices during the quarter. And then gas prices were up substantially at 40% to $4.81. You can see the results of our derivative activity at the bottom of the slide. That's included in derivative income or loss on the P&L.

Turning to slide 25 on production costs, first-quarter production costs were consistent with prior periods. As you may recall, we talked about it in February. Our fourth quarter was lower due to the adjustments related to third-quarter -- or, third-party transportation costs, and then lower-than-estimated ad valorem tax payments during the fourth quarter. So that was a benefit in the fourth quarter. It's kind of back to normal in the first quarter here.

Turning to slide 26, the Company's financial position -- still very strong financial position. We have plenty of liquidity, as you can see, with $257 million of cash on the balance sheet and $1.4 billion available under our credit facility. As you saw in the press release, it's further strengthened by the sale of Alaska that happened in April. And then if you look at the projection that Scott talked about -- $2.5 billion of cash flow this year, and that's basically a cash flow to EBITDA -- or debt to EBITDA of 1 times.

Turning to slide 27 for second-quarter guidance, this does exclude discontinued operations, so we're showing production of 173,000 BOEs to 178,000 BOEs per day. And then if you look at the rest of the items on this page, there are consistent with past guidance or results. So rather than going through each one of those, I'll leave those for your review. And then we'll go ahead and open up the call for questions.

Thank you.

(Operator Instructions)

Doug Leggate from Bank of America Merrill Lynch.

Thanks. Good morning, everybody.

I wonder if I could take a couple of questions, please. The first one, Scott, I just want to ask a big-picture question about guidance. Because I realize it's relatively recent that you gave your longer-term production guidance, but I want to dig into what assumptions you are making within that.

Your EUR ranges are quite wide, particularly in the Wolfcamp D, and obviously now in the Lower Spraberry. We've also seen some reference to the strip prices as the basis of your cash flow and your spending, and obviously oil prices are substantially higher.

So I'm just trying to get a feel as for what's baked into your guidance because it strikes us that you're probably being a little bit conservative.

And I've got a follow-up.

Thanks. No, we're still using a lower-type EUR in our analysis in regard to production growth. The average is about 700,000 to 800,000 barrels of oil equivalent.

So we are not modeling 1 million barrels of oil equivalent. And we are also not modeling -- a lot of these laterals are going out to somewhere between 8,300 and 9,300 feet. So we are being conservative. It's best to be conservative.

In regard to prices, as I mentioned earlier and we have stated publicly, is that we are looking at the strip environment. The strip the rest of the year is about $95, $96. It drops down to about $80 by 2019.

So that's one of our cases. That's the case that we're using in the three-year production, and also in the five years to double production. In that case, we're adding roughly about 5-plus rigs per year in the horizontal side in the Permian Basin.

And then we also have a case where, if crude continues to perform like it has in 2014, $95 oil. If it stays flat for the next several years, we'll be adding on 10-plus rigs.

Obviously that case would achieve much, much higher production growth rates. We do not have that case out there publicly.

Do you feel operationally, Scott, you've got the capability to deal with that in terms of securing drilling permits and line men and all that kind of good stuff? Is it easy just to turn up the dial that quickly -- to go from instead of 5 rigs, you're adding 10 rigs?

Well, the team's handled adding 11 rigs, basically, in a 90-day time period very well up in the north. So adding 5- to 10-plus rigs -- I wouldn't use the word easy, but we have over 1,600 employees in Midland.

We're the largest employer out there. We're way ahead of the competition, so we're very, very confident we can accomplish that.

Thanks.

My follow-up is -- not to take anything away from the Permian. But my follow-up is really in the Eagle Ford, given the success you seem to be having on the Upper Eagle Ford. And it's really a broad question, if I may because, obviously, you haven't really given us an update on how that type curve looks or well costs here recently.

But some of your competitors have been talking about this, particularly ConocoPhillips. They appear to be spending $3 billion drilling 200 wells. And they are telling us that their numbers are more realistic in terms of what they are spending.

And given that you guys are pretty much right in the same area, I just wonder if you could give some perspective as to what the economics of your Eagle Ford wells are looking like, what your current costs are.

And if I may tag on the end there, any update on your view of potential condensate exports? And I'll leave it there. Thanks.

That's a long question, Doug.

But Conoco -- $3 billion for 200 wells. That's $15 million a well. That seems high. But our well costs obviously are much less than that, especially with going to a two-string design.

So we're still at somewhere between the $7 million, $8 million well cost, with a 50% IRR. And that's coupled with the fact that we're getting about $8 to $10 a barrel off WTI for our condensate price.

In regard to the longer-picture question, we are still involved with several other innovative producers -- discussing with the Commerce Department, Administration, educating on Congress, in regard the importance to allow oil to be exported.

We still state publicly we think it will take a good two to three years to convince them to allow oil exports. I think it's important for this country to do it. It's important to keep this industry moving forward. So we are still confident that something will happen at some point in time.

Can I tie you down on the cost for the Eagle Ford wells fully loaded for infrastructure -- what is that number?

Well, infrastructure, Doug -- we're done with infrastructure. (multiple speakers) $7 million to $8 million is the number.

Remember, we put in place 13 CGPs, all the pods, all the production facilities, over the last 4 1/2 years. We're pretty much done with infrastructure.

That was extremely helpful. Thanks, guys, I appreciate it.

Charles Meade of Johnson Rice.

Yes, good morning, gentlemen.

I wanted to ask a question about the Middle Spraberry Shale and the Jo Mill Shale. It seems just a little bit out of your pattern to me. Maybe I'm over-interpreting what you're doing, but it seems a little bit out of your pattern of being conservative to say that these wells are tracking the type curve, given that we have -- it looks like about 15 days on one and 30 days on the other.

I'm wondering if there's more data than you're presenting here on this slide, maybe about the pressures or total fluid rates. Or maybe it's confidence from what you've seen with offset operators that has you guys so excited at this early stage about this.

No, overall, Charles, I don't think long term it's going to compete with the top four zones. But we need to let history play itself out. And we thought the same thing about the Lower Spraberry Shale when it first came on.

And so before we make any final decision -- but what's encouraging is that Jo Mill well is the first one we've got a great completion on, and it's still climbing even through yesterday's report.

So when you normalize it -- if you notice, both of those wells, the Middle and the Jo Mill, were shorter laterals. One is, I think, 4,200 feet and the other was less than 5,000 -- 4,700 feet lateral.

So when you normalize, though, to 7,000 feet, they are right on track obviously. And they are making the same amount of water. They are still performing the exact same way. It's in a lower-pressure regime.

The Jo Mill, if you remember, has been opened up on most of our 7,000-plus vertical wells. That's been opened up over the last 30, 40 years.

The Middle Spraberry Shale has not. And so we're just going to have to drill more wells. We're excited about it. It's still probably going to be very economical.

Some of the offset operators, I know, have opened up the Middle Spraberry Shale with very good results also. We're still the only Company, to my knowledge, that's drilled Jo Mill wells.

Charles, this is Frank.

I think it's important the point that Scott just made, that we've exchanged some data with some of our peers. We know how their Middle Spraberry Shale wells are performing. So this is very much along the same lines.

All right. Thanks, Scott and Frank.

And then, if I could, to go back to the southern JV part of the Midland Basin. I think that slide 18 you have is really a very powerful slide, primarily because it has that two-plus years of data.

But I'm wondering if also you could give a little bit of an update, if possible, on what the downspacing tests are looking like here in the south. I know that's supposed to be a second-half event, but figured I would give it a shot since we are within a month or so of that.

Yes, I think the downspacing tests, Charles -- this is Tim -- are still -- we're still working on them. We did a very large campaign in the Giddings area and we're still watching those well results. It turns out all the wells basically are producing similarly among the whole group of 12 wells.

We have another big spacing test that we're working on over at Rocker B, which is to the east. And the results actually look quite good there. We've downspaced a two-well pad -- these are Wolfcamp B wells -- to about 400 feet or so. I think we're at 70-acre spacing, compared to some offset 1,000 feet or, I'd say, 180-acre spaced wells.

It will take an extended period of time before we have this thing figured out. But there's an example where the offset wells look like they are performing in line with each other. And so I would just call it early days. We also have about three other areas in the Basin where we're doing offset spacing tests.

So you have to just bear with us as we get the results on this. We see the areas even in the north where we're going to be doing some testing as well.

That's great detail. Thanks, Tim.

Good.

Dave Kistler of Simmons & Company.

Good morning.

Hi, Dave.

Wanted to address the redirection of capital in the Northern Permian, with 5% more going over to the Spraberry portion of the play.

When we look at those that you highlighted and have shown in slides, it takes a longer time for them to dewater and bring production up to peak levels. With that in mind, capital is going over there; but your production targets are unchanged. However, that delay would indicate that production would shift out to the right.

So the gist of my question is, if I'm thinking about that correctly, you probably have greater confidence in the current production rates and the forward production rates of your Wolfcamp wells and the ability to hit that production target, given the way that flows.

Probably also factors into strong 2015 start to production. Is that a fair way to think about this?

Yes, I think first of all, those Lower Spraberry Shale wells increase will be in the last part of the year. So you'll see very little production from them.

But when you look at the type curves, it gives obviously a lot more stability and much flatter production. Even though it comes up slower, you don't get the pop like you do on the Wolfcamp wells due to higher pressure, but you get a much better decline curve.

And there's a chance that even a couple of these Lower Spraberry Shale wells could end up being better than any of the Wolfcamp A or B wells.

So eventually, going into late this year and next year, we'll probably be going to some four-well pads also, at least to three-well pads.

The only thing I would add, Dave, is that we're talking about 5% of 140 wells. You're talking about 7 wells out of 140. So it can't have too material an effect either way.

Okay. Appreciate that clarification.

And then going back to the Atlas agreement where you guys have accelerated the outlook or the need for a 200-million-a-day processing facility every 12 months versus every 18 months.

Can you talk a little bit about whether that's driven by PXD-specific activity concentrated near those processing facilities that are going to be potentially accelerated? Industry activity? Or is it just production rates are staying a lot higher than you thought?

Or there's some adjustment to mix? Just really trying to drill down into why that accelerated so much.

Yes. Obviously, our wells are performing much better. And third-party growth with the Spraberry/Wolfcamp at over 250 rigs and the conversion from vertical to horizontal, Wolfcamp is occurring much faster than expected over the last 12 months and continuing to accelerate.

So it's a combination of our growth; it's a combination of obviously the third-party growth; a combination of several companies going to the IPO market and raising capital, switching to horizontal drilling. So it's a combination of all of that, that's driving the fact that we've moved down from 18 months to a 200-million-a-day gas plant every 12 months.

And we've been spending time with Atlas over the last probably two years, convincing them that this is a huge play. It's the largest in North America.

And we need to have plants built essentially every 12 months. It may get down to a point to where we may need a plant every nine to ten months at some point in time.

Okay, appreciate that.

With that in mind, is there appropriate or do they have appropriate financing capacity to deliver on that?

Yes. We've been talking to the Chairman, Ed Cohen. He's promised me that they have plenty of financial flexibility to keep up.

Great. I appreciate the clarifications. Thank you so much.

Matt Portillo of Tudor, Pickering, Holt.

Good morning.

Just as we think about the resource potential as it continues to expand, you guys have previously given some targets on your long-term acceleration potential in the Northern Midland Basin. I was wondering if you have any updated thoughts in regards to how large of a program that could become in regards to the rig count.

And as we think about 2015 and 2016, what do you need to see from a well-production perspective or from a pricing perspective to potentially see upside acceleration on your drilling program?

Yes, as I stated earlier, under the strip price environment, we're adding five-plus rigs per year. Most of those will be in the north. And then in a $95 flat case, if we continue to march forward the current year into 2015, then we'll probably more likely adding ten-plus rigs per year above the next several years.

Under that scenario, the growth rate will be much higher than our 16% to 21% compounded growth rate. If prices continue to go up this year -- if all prices stay flat for the rest of this year, we may obviously at some time toward the end of the year add more rigs also. Anything else?

Great. And then just a second question.

In regards to the service cost environment in the Permian, I was wondering if you could provide some color -- just how you're seeing cost trends and if there are any areas in particular you see some pinch points on?

Yes, Matt, this is Tim.

I think in general, we see costs as pretty flat this year compared to last year. I think one of the main areas where we see a bump that's coming we have to compete with is in labor.

Labor is tight. It's across the board, whether it's rigs or pulling units or upstream activities, upstream operations. I think labor is one of your key areas.

I think as you go forward into 2015, we'll see a bump in rig costs. We are seeing some increases being proffered when it comes to pressure pumping for the second half of the year.

I don't think it's going to be substantial, or negatively really effect what we're trying to accomplish, as most of the stuff we're doing is internal. But there are signs that we are tightening, the rig count is going to be increasing through time, not only for us, but for others. And so it's a mixed bag. I think right now we'd call it more flat, other than labor. But going forward, we're seeing increased potential.

Thank you very much.

Brian Singer of Goldman Sachs.

Thank you, good morning.

Good morning, Brian.

Just wanted to pick up a little bit on the cost front.

You touched a bit on the rig completion side, though I wonder if your own vertical integration is partially why you're not seeing more. Maybe you would comment on that.

But I wanted to also touch on the midstream side, which is -- what impact do you expect to see on both your transportation costs and on your price realizations for oil-gas NGLs from deals like the Atlas one? And then just as yours and other Permian volumes grow?

Yes, I think the fact is, our transportation costs now are in a couple different areas.

One is gathering costs, which in some cases have to do with trucking; and other cases are, of course, pipeline. Those are -- those have been subject to some increases in the past, but they are pretty level right now. We're going to be moving more towards putting volumes on pipe, which is lower cost, trying to get up to about 75% of gathering on pipe.

When it comes to the longer transportation -- so for example, we're dealing with Magellan and the new pipeline systems. We've seen some increases in FT costs for those pipelines going forward.

Still, they represent quite excellent opportunities for us to make sure we can move volumes out of Midland and avoid the Midland-Cushing basis differential. But overall, as an example with Atlas, we have pretty much standard POP contracts on most of our gas processing that really are just more a matter of what is happening with both NGL and natural gas prices.

Got it. Is there some number you could put to the operating cost-per-barrel impact or any inflationary impact you see of trying to get the incremental -- or trying to get more barrels out of the Permian? Or what you would see next year and the year after versus this year? New builds, we assume would be more expensive as we go forward.

Yes, I think new build rigs -- I would say that the early estimate for 2015 would be 10% higher. And of course, that's not a very substantial amount of the well costs. But your completions might be in the same neighborhood, 10% higher, to the extent we're using third parties.

When you look at the rest of the operating costs -- like I say, labor is up probably 10% this quarter. Electricity, of course, is going up. And then that will have an effect as well. So I think we're probably looking at 10%-ish in terms of cost creep going into 2015.

Great, that's helpful.

And then, you've consistently monetized assets over the last few years, in part to balance your outspend. As we go forward, especially as natural gas prices and futures have moved up, do you see continued asset monetizations on more of the asset front?

And ultimately, do you see yourselves heading toward a pure-play Permian or pure-play Permian-plus Eagle Ford Company?

I think we're pretty much there, Brian, on a pure-play Permian/Eagle Ford Company today. We do have the three gas -- or call them gas NGL assets, two in Mid-Continent and the one in Raton. They are very long-life, very low-decline rate. It gives us an option on gas long term.

And all of our drilling activity is self-funding, in regard to when you give wells that pay out one to two years. And whether it's Eagle Ford or whether it's in the Permian, it allows us to continue to accelerate.

So we have no further needs for asset divestitures, other than Barnett. We hope to get Barnett obviously done sometime by the end of the year.

Great, thank you.

John Freeman of Raymond James.

Good morning.

Hi, John.

Currently with you all running the 11 vertical rigs in the Spraberry and you all own 15 vertical rigs, I just have a couple questions along those lines. Are any of your vertical rigs being used by third parties?

And over time, as more and more of your horizontal drilling starts to help meet that continuous drilling obligation you have, should we assume that in 18 months or so that you may look at just selling the vertical drilling rigs?

John, you're ahead of us a little bit. We have actually sold our vertical rigs, and we do not currently operate any of our own rigs vertically.

All right. And then on the Upper Eagle Ford, Marathon had some pretty positive comments this morning on that, following six wells and one of them was pretty big. They mentioned -- and they're obviously kind of in the general same area as you all -- and they mentioned that they were, in some cases, mixing the Upper Eagle Ford and the Austin Chalk.

I know you all aren't giving necessarily well results yet, but maybe just any additional color you could provide on the Upper Eagle Ford and what you've seen so far.

Yes, John, I think our objective right now is to complete those wells and keep it all in the Eagle Ford. That's just been our mandate internally from the standpoint of our geo-science group, and that's what we're doing. So we're really not trying to frac up into the Austin Chalk.

That's great. Great quarter.

Thank you.

Arun Jayaram from Credit Suisse.

Good morning, gents.

Good morning.

Tim, I just wanted to see if you could elaborate a little bit on potential improvements in spud-to-POP ratios. I just want to see if maybe you could use the south as a guide, and give us a sense as to where you think those could go to in 2015.

By south, do you mean Southern Wolfcamp?

Yes.

Well, first of all, that's where the money is to try to reduce the spud-to POP-timing. As I already mentioned to you, we are already doing quite a bit there with regard to SIMOPs to try to actually improve those numbers. And we've been very successful so far.

I think the real question is, what can we do in terms of going even past three-well pads to four-well pads, maybe even higher, and increasingly use SIMOPs to make sure that we cut days off?

What we're also trying to do, of course -- and we've seen some success already over the last year or so we've been drilling wells there -- is actually just reduce the time on wells. So this has to do with just drilling efficiencies. It has to do with basically focus on operations. It also has to do with your completion profile.

But I think the answer is, today, we're probably out at 130 to 140 days, something like that. And I think it's not unreasonable for us over the next couple years to drop 15 to 20 days.

Right. And then you do end the year with 65 horizontal wells in your inventory, which haven't been depleted. So 2015 should start off with a pretty good, healthy ramp. Is that fair?

Yes, I think with the situation with your three-well pads is you're actually spudding the wells, just drilling the surface and intermediate section first. And then you go back to drill the lateral sections of each well.

So when we talk about spudding wells, it really isn't necessarily the case that our drilling wells particularly. We�re in the process in most cases of drilling surface and intermediate and lateral. Therefore, it's a situation where a rig can have three wells that are in progress even before the three-well pad it was drilling on has wells on production.

So you're right. When we have the frac bank, I guess you would call it -- or this is POP bank, in this case -- out there at 60 wells, we're going to be in pretty good shape to be able to hit the first quarter of 2015 running pretty hard.

That's great. And just my final question. Scott, you talked about what kind of underpin, you're plan out to 2018 of five incremental rigs at the strip. I know you have a pretty conservative Board.

I just wanted to see your thoughts on -- can you generate the CapEx needs -- internally generate it through -- obviously you have the Barnett sale -- or thoughts on funding that growth.

Yes. If you look at the return slide that we've been showing, you have these wells pay out in one to two years. Because of the short payout, it allows us to get cash flow returns so strong that it allows us to reinvest and continue to add rigs without going to the equity markets, or without further divestitures other than Barnett. And that's even with the strip price environment going down to $80. And that's adding five-plus rigs per year.

And then, as I said, the upside case of $95 flat for the next several years, we would obviously have much higher growth rates in our 16% to 21% compounded annual growth rate under that scenario. But we'll be adding ten-plus rigs per year. And that's, again, self-funding.

That's great, Scott.

Anything else?

That's all I've got. Thanks.

Will Green of Stephens.

Good morning. I wonder if we could talk about the -- you touched on the completion changes you are seeing, kind of an uplift on start rates and that sort of thing. One thing you mentioned was pumping more sand. Are you still using Brady Brown in all the Permian?

And then, moving forward, looking at the ramp you have, will Premier Silica still serve all of that need? And are you doing any resin-coated in some of the deeper parts at all?

The answer is, almost 100% of what we pump in our Permian Basin wells is Brady Brown. We have a little bit of white sand that's used from time to time, just near well bore. But principally, it's almost all Brady Brown.

Going forward, what's going to be needed, because of the substantial rig count increase Scott was alluding to, is an expansion of our Brady mine. I anticipate we'll probably commence operations on that expansion sometime next year and have sand available in 2016. So we're actually going to be building out the mine to meet our needs.

Got you, thanks. And then the other one I had is on the way these pads are going to be configured. You already mentioned that you'll be doing a little more Spraberry work this year. But how should we think about most of these pads being configured?

Is it going to be BBB? Is it going to be ABA? What do you think at this point is the best way to pair these wells up together, being mindful that probably different areas of the Basin are going to be a little bit different?

Yes, I think that's a great question. In fact, that's the question we're trying to answer this year is what is the optimal combination of wells on pads so as to optimally develop an area?

Realizing that it's pretty definitive, especially if we're talking about the northern areas that we have, quite excellent potential in the Wolfcamp A, B, D and the Lower Spraberry Shale. I think you can see from our data that's pretty definitive.

By the same token, we're trying to get the data that we were talking about earlier more fully enhanced regarding the Middle Spraberry Shale and more Jo Mill wells that are properly completed. So I think we have to hold off until we really know that.

Because you could be in a situation where you're drilling four or five stacked laterals on a staggered basis on one pad. And then you might be drilling multiple wells on a pad, not just in this three or four wells per pad.

So we need to hold off answering that until we really understand the full data set. But I think it's likely that we're going to have multiple-zone stacked laterals when we finally get to that campaign.

Got you. Thanks for the color.

Yes.

Leo Mariani of RBC.

Hello. Just wanted to get back to the Jo Mill and the Middle Spraberry in the northern part of the Midland here.

You talked that your Lower Spraberry had the most oil in place. Perhaps you can give us a relative comparison of oil in place for the Jo Mill and the Middle Spraberry relative to the Lower here.

I think we've calculated it would be about half in each case, on a per-acre basis.

Okay, that's helpful. And it looks like in the southern part of the Midland, looks like most all of what you're doing is Wolfcamp, from what I gather from your presentation. Is there going to be any Spraberry testing any time this year or next year in the Southern Midland?

Yes. We're actually going to do some this year and some more next year.

Most of our Spraberry shale wells are in the north half of our 845,000 acres. And so we'll be drilling some later this year and next year in the southern half, including the JV area where we own 100% of the Spraberry rights. We'll be evaluating the southern 400,000 acres and several Spraberry Shale wells over the next 6 to 12 months.

All right. Thanks.

Amir Arif of Stifel.

Thanks, good morning.

Scott, I appreciate your color that you don't need to sell any additional assets beyond what you've got out there already to fund your five additional rigs as you go forward. But at the same time, you said you would like to add ten rigs if you had a cash flow at $95 oil.

Any thought or desire to monetize some of your midstream assets, either (inaudible) MLP or selling to an MLP to free up some of that capital to accelerate it, just given the success you are having in the Permian?

Well, 5 rigs gets us to 80 rigs. And 10 rigs gets us to roughly 120 rigs at some point in time. And so nobody, to my knowledge, in any of these shale plays has been running anywhere between 100 -- not one single company. So we're accelerating already under the current plan.

In regard to if we had divested, when you divest of your processing assets, you essentially lose control. I would be very concerned. Our execution risk would go up significantly, due to the fact that we have an ownership with Atlas that's allowed us to educate them and allowed us to both, joint together, accelerate.

When you lose control of your gas processing assets, your execution risk goes up significantly higher. So that's one of the reasons why we haven't looked at it.

Okay, I can appreciate that.

And then a quick question. You've given second-half guidance at 195,000 to 210,000 barrels. Can you give an estimate of where you think you'll be exiting the year on your production?

We will do that later on sometime, but obviously not now. But obviously, it will be way over 200,000-plus barrels.

Okay.

And then finally, on the Permian Basin. Again, (inaudible)] here. Any color on 2015 hedges for the basis? Or is there any concern for you out there?

What? Say it again now.

Your Permian Basin?

Oh, yes, it drops to 375 July 1 on going forward, long term. That's with the Oxyline bridge techs coming on July 1.

It stays pretty much that over the next three to five years. As Magellan comes on, the expansion comes on this year, and with the other two lines that are coming on in 2015, we do have capacity on those going to the Gulf Coast.

A lot of our crude is going to be priced off of LLS down in the Gulf Coast. We'll have a balance of mostly Cushing and LLS pricing, so we see no need at this point in time to do any hedging.

Okay, thank you.

Michael Hall of Heikkinen Energy Advisors.

Thanks.

A lot of mine have been answered. I just wanted to come back to the question around efficiencies, just from a little bit of different angle.

As I think about 2015, is it fair to think that the ratio of POP to wells drilled in the northern program will approach that of the southern program in 2015? By that, I mean --

That's the right way to think about it.

Realizing when you're ramping up, you get this massive effect of creating a POP bank as you're waiting on all the operations -- the SIM ops and the three-well pads and the four-well pads -- to get to the point where all the wells can be put on production. Once you're at a point where you're at a run rate of rigs that are stabilized, that number comes dramatically down.

Now, the question is how many rigs we add next year and when. So to the extent we add five, or let's just say ten rigs in the north next year, we will still see that effect until we get more stabilized. But it will be much less dramatic, simply because we have a much bigger base of production at that point. So you'll see less swings on a percentage basis.

Okay, helpful.

And then on the Lower Spraberry and the Middle Spraberry wells, what are the differences in operating costs on those wells, given it seems like quite a bit more water to be handled there?

Yes, I think you are right. You do see more water in those zones.

But I think our water handling is really not going to be a very big percentage of the cost increase. I would say it's relatively immaterial.

Okay.

And then on the topic of water. In the ramps in activity you and others are projecting, we've heard some rumblings around just sourcing water in the Midland Basin. It could get tight going forward. Any color around that, or (inaudible) secure frac water?

We are, Michael, very, very active in making sure that we have adequate water supplies. And it's using, essentially, an all-of-the-above strategy. Which has to do with acquiring non-potable water sources, acquiring effluent water sources from some of the municipalities, using brackish water. Very much limiting freshwater is the objective of all of this exercise.

And then finally, we are doing a substantial number of pilots on water recycling and cleanup. We have in place a new LLC inside the Company, which is called Pioneer Water Management.

Their main job is to get water to our locations for fracking and drilling. Based on what I've seen in terms of early returns, we're making a tremendous amount of progress in this regard, such as to be in a situation where water would not be an issue and we could deliver water relatively cheaply to all of our locations.

It's going to take capital over the next several years, and so that shouldn't be ignored. But the fact is, we're all over this. And I think we're going to be very successful.

Okay.

And then on the topic of capital, the $400 million of infrastructure land in science and the $100 million of gas processing facilities and other ancillary costs. How long do we going to think about that as a run rate as you ramp up like you've done the Eagle Ford? You have moved beyond that. How long until we're through that spending?

I think the big item that's going to come down is the facilities numbers should come down substantially going into 2015, 2016. Because we pretty much will have completed most of our facilities if it was in the Permian Basin.

Okay.

Land will continue. We're still going to go after contiguous acreage, trying to upgrade and achieve longer laterals. So we'll always have a land budget pretty much fairly equal over the next several years.

And on equipment, I think Tim's probably already commented. But longer term, based on the current rates we see, we'll probably continue to do the replacement equipment only. And start using more and more third parties over time.

But it all depends on the payout and the charges that the third-party companies are charging on frac rates.

Okay.

And then, last one of mine was just as it relates to the new plant and the new buildout with Atlas. Are there any constraints from a processing standpoint between now and when the new plant comes on in Martin in 2015?

Do you have enough room at present? Obviously you can kind of navigate around it a bit.

Yes, we've already mentioned publicly that we've built into our guidance for the second half of the year that there's probably about four to five months of where we're rejecting ethane in our guidance. Obviously, we get a pick-up in cash flow where it's neutral.

So that's built into our guidance. We're looking at ways around it. But at this point in time, we don't know whether or not we can feed off some of the gas to other operators in the system for a period of about four to five months. So that's an upside.

But right now, it is built into our guidance before the -- and then there's a chance that we could get the plant coming on in fourth quarter up a little bit earlier also. But that's not built in also.

Okay.

Can you remind me roughly how much volume is being rejected? Is that potentially a little bit of an uplift in 2015? Could you quantify that?

In 2015, there is no rejection because the plants coming on right now are fourth quarter of 2014.

That's what I'm saying. What's the potential uplift in 2015?

The rejection will basically start around June and could go through October or November. That's what we have built into our guidance.

That's probably about 1,000 or 2,000 barrels a day net that would represent ethane rejection that would be picked up in 2015, versus if and when we face this issue during the second half of this year.

Okay, that's all. Appreciate it. Thank you. Good quarter.

Doug Leggate of Bank of America Merrill Lynch.

Please go ahead, sir. Doug, your line is open.

What's the next question?

He must have dropped off. Are there any other questions?

Phillips Johnston of Capital One.

Hello, thanks.

In the Southern Wolfcamp area, you're focusing on the higher return areas in the north. Just wondering if you can give us a ballpark range of what percentage of your overall acreage position that area represents?

And also, if you can just discuss the differences in returns in that area versus the acreage out there in southern Reagan?

Yes, Phillips, just to give you a feel for it, we're probably making 60% to 70% returns in the north based on the area up there typically generating 500,000, 600,000, 700,000 barrel BOEs.

And in the south, of course, in some of the areas in the very south, it's in the neighborhood of 400,000 BOEs. So I would say that in terms of a split, it's probably two-thirds of the acreage are acres where you have this high rate of returns in the north.

Okay, and then in the south, obviously about one-third of your wells this year are planned for the A, the C, and the D. Of those three zones, which is the most de-risked at this point do you think?

I think the A is the most de-risked in the Southern Wolfcamp. We're just now putting our first C well on production. And we're just now going to be producing our first D wells.

Okay. Thank you.

Sven Del Pozzo of IHS.

Yes, just quickly, could you walk me through the thought process that allowed you to eliminate the extra casing string in the Eagle Ford?

I think if you look at it, and you look at ways to reduce costs at all times, I think that it has been exactly the same things that a lot of other operators have done. And we've just been piggybacking on that. But basically, it's understanding and getting experience when it comes to pour pressure and controlling mud weight.

We're drilling in the deepest part of the basin on average, so this is something we've held off doing for some time. But as we've gotten more understanding, we think it's pretty clear we can eliminate a string.

And we've been very successful in doing that. So I think we've de-risked that 100% now.

So is the lateral portion of the well shorter, but you're getting similar well performance to one where the lateral is longer?

Yes, I mentioned on the call that our lateral lengths have increased, actually pretty substantially. And we're getting really quite excellent well performance. Actually, better well performance than we ever have, when you couple extending the lateral plus our optimization campaign, when it comes to how the wells are completed.

So actually, the wells are doing significantly better in combining those effects.

And how much of your total acreage position in the Upper Eagle Ford is prospective?

About 25%.

All right, thank you.

And that concludes today's question and answer session.

At this time, I'll turn the floor back over to Scott Sheffield.

Again, we appreciate everybody taking the time and effort to listen to our first-quarter call. Look forward to talking to you on our second-quarter call in August. Thank you.