Pioneer Natural Resources Management Discusses Q2 2013 Results - Earnings Call Transcript

Aug. 1.13 | About: Pioneer Natural (PXD)

Pioneer Natural Resources (NYSE:PXD)

Q2 2013 Earnings Call

August 01, 2013 10:00 am ET

Executives

Frank E. Hopkins - Senior Vice President of Investor Relations

Scott D. Sheffield - Chairman and Chief Executive Officer

Timothy L. Dove - President, Chief Operating Officer and Director

Richard P. Dealy - Chief Financial Officer and Executive Vice President

Analysts

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Gilbert K. Yang - DISCERN Investment Analytics, Inc

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

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Arun Jayaram - Crédit Suisse AG, Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

John Freeman - Raymond James & Associates, Inc., Research Division

Michael Hall

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Rehan Rashid - FBR Capital Markets & Co., Research Division

Jonathan D. Wolff - ISI Group Inc., Research Division

Operator

Welcome to Pioneer Natural Resources Second 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 website to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Investor Presentations.

This call is being recorded. A replay of the call will be archived on the Internet site through August 26.

The company's comments today will include forward-looking statements made from -- 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.

Frank E. Hopkins

Thank you, Marco. Good day, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Scott is going to be the first speaker. He'll provide the financial and operating highlights for the second quarter of 2013, another strong quarter for Pioneer. He'll then review our capital and production growth outlooks for the remainder of 2013. This will be followed by a recap of our continued strong drilling results in the horizontal Wolfcamp play across Pioneer's extensive northern Spraberry/Wolfcamp acreage position. After Scott concludes his remarks, Tim is going to discuss our drilling plans in the northern Spraberry/Wolfcamp, as well as the southern Wolfcamp joint venture area and the Eagle Ford Shale. Rich will then cover the second quarter financials in more detail and provide guidance for the third quarter. After that, we'll open up the call for your questions.

Before moving on with the call, there is one procedural item I need to cover. Please recall that during May, we announced that Pioneer had submitted a proposal to the Conflicts Committee of the Board of Directors of the general partner of Pioneer Southwest Energy Partners. The intent is to acquire all of Pioneer Southwest's outstanding publicly held units in exchange for Pioneer common stock. Pioneer is waiting to hear from the Conflicts Committee on this proposal. If such a transaction were to take place, we would be required to file a registration statement with the SEC, and so we will be unable to discuss the proposal during this call.

With that, I'll turn the call over to Scott.

Scott D. Sheffield

Good morning. Thanks, Frank. First slide, we had second quarter 2013 adjusted income of $154 million or $1.10 per diluted share. Second quarter production, 176.2 thousand barrels a day equivalent. When you add back in our 1,400 barrels a day of ethane rejection primarily in our Atlas plants associated with that 177.6 thousand barrels a day equivalent. We're up about 5,000 barrels a day, or 3%, compared to first quarter, driven primarily by horizontal Wolfcamp shale and Eagle Ford shale growth profile.

Second quarter again, production negatively impacted by the unexpected ethane rejection of about 1,400 barrels oil equivalent per day, primarily in our southern area of JV with Atlas. With ethane around $0.25, we need a movement probably another $0.02, $0.03, $0.04 before we see ethane rejection stop [ph].

We're narrowing our production growth guidance range from 12% to 16%, to 14% to 16%. We're tightening that range. Again, very important in our northern Spraberry/Wolfcamp horizontal drilling program were announced in our first Wolfcamp A. If you remember, we're about 2,000 feet deeper in this area. Very highly successful once again on the Hutt lease, where our first Wolfcamp B was announced several months ago. We had a 24 IP peak rate of over 1,700 barrels a day and a 30-day average rate of a little over 1,100 barrels a day with 74% oil.

In addition, an update on our Wolfcamp B well in Martin County. Our first well there, the Mabee K well which we announced in late May, it had a peak rate 1,572. Again, a new 30-day average production rate of 10,040 (sic) [1,040] with 76% oil.

We had cumulative production from the first Wolfcamp B interval well, the Hutt well, in Midland County. What's interesting, in 6 months, it's reached 140,000 barrels of oil equivalent. If you remember, our typical Wolfcamp -- Spraberry/Wolfcamp vertical well takes 30 to 35 years to produce a 140,000 on a vertical well. So we did that in 6 months.

What's also interesting in our Hutt lease, which is becoming very popular for us, it's made up about 11,000 acres, 93% net revenue, with 700 potential locations in 6 intervals at about 800,000 barrels. It can eventually yield 0.5 billion barrels just that lease of 11,000 acres net to Pioneer.

Turning to Slide #4, additional highlights. If you remember, we did increase from 1 rig to 5 rigs in the second quarter in our northern Spraberry/Wolfcamp drilling program. Those additional 4 rigs were primarily late in the second quarter. We're currently drilling multiple zones, both the Wolfcamp, Jo Mill and Spraberry shales. In addition, we're moving 2 rigs to an acreage position pretty much on the Andrews/Martin County line during the third quarter.

In addition, with the success of the Hutt A well, we are moving up several A wells in the Q for late 2013 and early 2014. We now have 5 horizontal wells on production in the north. They include our 2 Jo Mill wells, which are in the Giddings area. We have 6 wells awaiting on completion and 5 wells currently drilling. So it's pointing toward somewhere between 6 and 11 wells we could report on by the November call.

Our update on our southern Wolfcamp joint venture horizontal drilling. If you remember, we did close our joint venture on May 31. June production was lower by 4,000 barrels a day. Because of that, selling 40% of 10,000 barrels a day or 1,300 barrels a day for the quarter. We placed 22 new Wolfcamp B wells during the quarter with IP rates up to 1,000 barrels a day equivalent. Well results are meeting expectations.

In addition, we're still continuing to lower well cost. As we have mentioned before, we were targeting 7,000-foot laterals. We are now up to 8,300-foot laterals on average. Our well costs are $7.5 million to $8 million.

Total cost. If you look at a 7,000-foot lateral, that puts the total well cost back to about $7 million or less. This does include the benefits of lower slickwater frac, and also our hybrid fracs are being reduced.

In addition with the recent run-up in crude price and especially WTI, over the last 3 weeks, we have significantly increased our hedge positions for finishing up '14, up to 60% in 2015, and from 0 really up to 15% in 2016. And we're continuing to move these coverage ratios up, especially in both '15 and '16 as we speak, again, primarily using 3 ways, protecting the downside with upside.

In addition, with the closing of the joint venture, we now have $700 million cash on hand and our debt-to-book is down from 26% to 22% at end of second quarter.

Slide #5, on our CapEx. The important thing is our CapEx remains the same at $3 billion, so no change. I won't go into any more details on this slide. But essentially, it's being funded with cash flow. We're using $95 oil and $4 gas the rest of this year. Obviously, we're seeing higher prices now. That's generating cash flow of $2.3 billion and again, with $700 million cash on hand.

Going to Slide #6, in regard to our production growth. We are narrowing our guidance range from 175,000 to 181,000, to 177,000 to 181,000. Also, we are bringing out both third and fourth quarter. We'll see a significant jump in fourth quarter, primarily due to the fact that the timing of POPs from pad drilling. We're doing pad drilling in Eagle Ford, pad drilling in our southern JV with Sinochem and also we're doing pad drilling in the north.

In addition, we started our last 4 rigs in the north late of second quarter, so we won't see the impact to those until late third quarter, primarily fourth quarter. That's why you're seeing a big jump, 185,000 to 195,000 range for the fourth quarter of 2013. Again, 62% liquids, moving towards 70% liquids in 2015.

Slide #7 just backs that up of how we got to each of the numbers. The big change again, emphasizing the POPs from both Spraberry/Wolfcamp and Eagle Ford, first half of 93 going to 142 the second half, and most of the ones in the second half are late third quarter and going into the fourth quarter. Again, you see the effects of the Sinochem sale and the ethane rejection going into the third quarter.

Slide #8. Again, the 2 highlights. In yellow is the Hutt A well, Wolfcamp A well coming on at 1,700 barrels a day, located right next to the Wolfcamp B well that's produced over about 140,000 in 6 months. Again, that's on our Hutt lease. The Wolfcamp A, just to remind people, of all the Wolfcamp zones, the Hutt A has more -- I mean, the Wolfcamp A has more oil in place than any other Wolfcamp zone throughout the area. The key really is to contain the frac. We did it on this well, so it opens up -- we're about 2,000 feet deeper, but it opens up potentially the entire Midland County and Martin County, again, for that Wolfcamp A interval.

And also, the Mabee well, 1,570 barrels a day equivalent, 76% oil, again, performing tremendous. The rest of the map shows the other wells that we have been showing, both lower Spraberry Shales, Jo Mills and our Giddings wells that were drilled over almost 2 years ago.

I'm looking at Slide 9. What's interesting is the decline curve on these 3 wells, both the 2 Wolfcamp B wells in Martin and Midland, and then the recent Wolfcamp A well. What's interesting is that the Wolfcamp A well is starting to exceed the potential decline of the original Hutt well Wolfcamp B that's made 140,000 barrels.

A couple of things have happened. We've modified our heater treater. And secondly -- to reduce back pressure. And secondly, we have just recently installed it on gas lip. So we generally anticipate a slight bump. So it'll be interesting to watch, but it is moving past the curve. These 3 wells are way exceeding way above the 650,000 barrel type curve, pointing toward somewhere between 800,000 and 1 million barrels for each of these 3 locations.

Finally, Slide #10, in summary. Again, we have a tremendous asset base. We have over 9 billion barrels. We'll continue to grow that significantly over time as we report the next set of results. The drilling program is focused primarily on liquids-rich areas, both the Eagle Ford, Spraberry vertical and the horizontal Spraberry/Wolfcamp plays. We have a great growth profile of 15% plus over the next several years. Vertical integration substantially improving execution and returns, great hedge position over the next 3 years and again, a great balance sheet. Let me turn over to Tim to give you more details.

Timothy L. Dove

Thanks, Scott. I'm on Slide 11 now. We are clearly making a lot of good progress in terms of executing on our northern drilling plan in the Permian. You've heard some of that from what Scott had to say. In the next 3 slides, I'm going to cover -- provide a great deal granularity on our plan moving forward.

We've tweaked our current plan slightly. The plan still is to spud 30 to 40 wells this year in 6 different intervals. Each of these intervals, we believe, are prospective on plus or minus or even in some cases, more than 600,000 acres. Now the current plan that's shown on this slide is to drill about -- or spud about 20 to 25 wells in the Wolfcamp, the D, B and A zones. While at same time, we'll be spudding 10 to 15 wells in the Spraberry zones, the middle and lower Spraberry shale, as well as the Jo Mill. So this will be the subject of the 5-rig campaign, targeting spudding those 30 to 40 wells in 6 different zones.

Costs have been coming in at about $7.5 million to $8.5 million in the north for 7,000-foot laterals. Of course, it is deeper in the north than it is in the south. Now we continue to spend money in the sense of science and facilities for these new wells. That is to say, micro-seismic in most every case, drilling pilot holes, taking cores and using sophisticated long suites. The idea of being gathering data so that we progress into appraisal and we'll have all that behind us.

Turning now to Slide 12. The map here shows the general areas we're going to be drilling and specifically, they're shown by the red stars on the graph. Those are in Midland and Martin and soon to be, east Andrews County. Scott alluded to this, where 2 rigs will be heading up there. It's about 15 miles northwest of the Mabee horizontal well in Martin County.

Specifically, though, going forward, we'll have 3 rigs focused on Wolfcamp shale drilling in Midland and Martin Counties and 2 rigs focused on Jo Mill and Spraberry shales in those same counties. And then after that, we'll be moving a couple of those rigs during the third quarter to drill Wolfcamp and the Spraberry shale wells in Andrews County. We continue to move much more towards pad drilling to gain the efficiencies associated with that. Of course, it leads to delays when you look at it from a standpoint of spudding the first well to putting both wells on production. We currently calculate that to be about 120 to 150 days, in this case, longer than usual, simply related to the fact we have all that extra science to do in the early stages of the project.

And this leads to -- as you know, when you look at the rest of our peers, we're in a similar situation with pad drilling. It leads to a relatively lumpy production profile, which we are depicting later in my presentation. Suffice it to say, we're well on the way to executing this $400 million program for this year and looking at adding 3 more rigs next year.

Pretty clearly, though, when you look at this area, production will be skewed to the later part of the year due to pad drilling.

Now I'm going to turn to Slide 13 and this is a lot of granularity, but it does show the effect of pad drilling and the details of where these pads are going to be drilled and by zone for the second half of the year. And we expect to add about 20 new wells on production in the second half of the year. Again, a lot of that is back-weighted towards the fourth quarter as you can see. Each of these bars represent 2 wells. As you can see, for example, the Wolfcamp B and D, that's 2 wells over a couple of quarters being drilled. You'll see on the lower part of the graph, we have about 6 wells. So there's 3 bars effectively coming on production during the third quarter, which we will be able to talk about in the November call and perhaps, a few more depending upon the exact timing. And I would -- concurrently, the thinking is we would have a minimum of 6 wells on production just, again, due to the effect of pad drilling. So out of the 20, you'll see more information as we get into the first quarter. And it's very clear to me, we'll be seeing a lot more data on the early northern well results as the next couple of quarters transpire.

Turning then to Slide 14. The southern Wolfcamp drilling campaign is in full swing with 7 rigs running. We put 22 new Wolfcamp B wells on, as Scott has already mentioned, with very strong expectations, and those came in along the lines of those expectations, up to 1,000 BOE per well and very high oil content importantly. We've already mentioned the fact that slickwater fix -- slickwater fracs have a very significant benefit from a cost standpoint. We also are reducing the cost of our hybrid gel fracs by using less expensive chemicals and changing how the wells are completed in terms of the number of clusters per stage and so on. And so we're seeing benefits to reduce cost whether we use gel or slickwater, and the results seem to be the same in terms of the productivity of the wells.

Again, the plan is to move from about 7 rigs this year to 10 rigs next year and so on, increasing after that. We're well on target to drill our 86 wells this year. As you look to the second half of the program, we will be testing multiple Wolfcamp zones, the A, B and D. As Scott already mentioned, our costs are coming in basically as expected, about $7.5 million to $8 million for the 8,300 average lateral.

We are in the process of extending laterals. We have about 20 wells, maybe even slightly over 20, that we'll be drilling in 2013 to somewhere in the neighborhood of 10,000 feet. The economics still support this lengthening in a significant way, with about 20% increase in cost generating a substantial increase in EURs, estimated to be somewhere in the neighborhood of 40% to 60%. And we'll be doing about 70% pad drilling in the south.

Typically, it's 3 wells in the south and that puts your spud-to-POP length out to about 150 days. Again, you expect to see as a result of that lumpy production growth as we get into the third and fourth quarter, with a lot of the production increase is skewed into the fourth quarter.

A real important note here, although we don't give a lot of information on it, is the fact that we're testing downspacing using staggered interval drilling in both the upper B and lower B. All of the resources that are discussed in our investor relation materials are based on 140-acre spacing. This testing is now being done at 80 acres and we see no reason to believe that won't work, but we're testing it as we speak. We'll have much more to say about that over the next couple of quarters.

Now turning to Slide 15. The result of all this activity is continuing growth in the Permian basin. As you can see, we produced about 80,000 BOEs per day in the second quarter. Of course, that was negatively affected by the ethane rejection Scott mentioned. But the fact is we are tightening our range to the upside for the Permian basin up to about 77,000 to 80,000 barrels equivalent per day this year compared to our prior range of 75,000 to 80,000.

We do have the new gas processing plant on in Driver. But in addition, a new plant has been announced by our partner for the addition of another 100 million cubic feet a day in the second half of 2014 and another 100 in the first part of 2015. So we're well ahead of taking care of our needs when it comes to gas processing for future production.

We do continue to use 15 vertical rigs. As you know, we need to meet continuous drilling obligations in order to preserve our leasehold, both vertical and horizontal leasehold. We did drill about 73 vertical wells in the second quarter and have now brought our frac back down to minimum levels, I think, put about 90 wells on production. Almost every single one of those wells will be deepened to the Strawn and the Atoka and so on.

And just as I showed for the northern pad drilling, we see the same effects in the south in terms of the effects of production, hitting more in the fourth quarter than it does in the third. Overall, we expect horizontal production from the Permian to increase from about 2,000 barrels a day last year to a range of 11,000 to 14,000 this year depending upon the exact timing of bringing wells on production.

Turning to Slide 16. Eagle Ford Shale now is effectively a well-oiled machine for Pioneer. You can see that we continue to set new production records. We drilled 33 wells in the second quarter, on target to drill the 130 wells that were planned this time this year, drilling with only 10 rigs, while drilling the same number of wells we drilled with 12 rigs last year. In the Eagle Ford, we are typically in the range of 2 to 6 wells per pad. We're that much more further advanced in terms of the development here after now being in the play 3 to 4 years. The average perhaps is about 100 to 120 days spud-to-POP time for a 3-well pad. But it does save substantially in terms of the per-well cost somewhere in the neighborhood of $600,000 to $700,000 per well. It's become a recurring theme. For the third time, I'll tell you we'll see some lumpy production growth as a result of that, as we substantially ramp up our pad drilling. And you can see our production in the fourth quarter will be growing because a number of wells we POP-ed at the end of the third quarter and the fourth quarter will increase compared to earlier in the year.

As I'm also mentioning in the southern Wolfcamp, we're also testing downspacing in the Eagle Ford. Our original planning on Eagle Ford had us at about 115-acre spacing. We're now testing 40-acre spacing, especially in some of the more oily areas. We'll have more to say about that after we get the results in the next couple of quarters. And we're also similarly extending laterals, now trying 10,000-foot laterals compared to our recent averages of more like 5,500 feet. And so what we're doing, of course, is expanding our knowledge base and continually improving and hopefully, continually improving the economics. One way to do that is to use more white sand. We have about 75% of our program using white sand, and the results look very strong and they substantially are reducing our frac cost. Now the estimate is over $1 million savings by directing white sand to the completions.

Well costs are well stabilized in the neighborhood to $7 million to $8 million. So I'm going to stop there. And in essence, what I can tell you is the execution in our assets is at a high level and should lead to the future performance that will be very solid.

With that, I'm going to pass it over to Rich for a review of the second quarter financials and third quarter outlook.

Richard P. Dealy

Thanks, Tim. I'm going to start on Slide 17. Net income attributable to common stockholders was $337 million or $2.40 per diluted share for the quarter. It did include unrealized mark-to-market derivative gains of $66 million or $0.47 per diluted share. Also included, unusual items, aggregating $117 million or $0.83 per diluted share, primarily made up of the southern Wolfcamp JV gain that we had recognized on that transaction when it closed at the end of May. So adjusting for those items, we're at $154 million or $1.10 per diluted share.

Looking at the middle of page where we show our second quarter guidance and then the results, how they actually came out, you'll see that we're within guidance. On all the items, we're on the positive side of guidance. As you scan down there, you'll see that. I'm not going to through those, but they're there for your review.

Turning to Slide 18, price realizations. You'll see that our oil price realization improved by 3% relative to the first quarter, up to $90.82. This is primarily driven by the differential between Midland and Cushing coming down during the second quarter. If you look at NGL prices, we are down 7% to $28.19. This is primarily driven by the heavy end of the NGL stream, the butanes and natural gasoline prices coming down during the quarter. And then, as you're aware, gas prices were up 19%.

Looking at the bottom of this slide, we did have cash derivative settlements that were positive during the quarter on all our products. And so they added income representing $1.07 to oil, $0.12 per barrel on NGLs and $0.71 per Mcf on gas.

Turning to Slide 19 to look at production costs. You can see we're very consistent with both the first quarter and the fourth quarter. Costs have been coming in flat so no significant changes here and expected to continue into the future.

Turning to Slide 20. Look at our liquidity position. The company, as Scott talked about, has a very strong financial position. We have net debt of $2.1 billion, strong liquidity position at $696 million of cash on hand and a $1.5 billion undrawn credit facility. You can see from the table in the middle that we have no near-term bond maturities and the company is in excellent financial condition.

Turning to Slide 21, third quarter guidance. Scott talked about production guidance of 174,000 to 179,000 BOEs per day in the third quarter increasing to 185,000 to 195,000 BOEs a day in the fourth quarter, primarily as a result of the timing of bringing wells on associated with pad drilling. So that's there. The rest of these items are very consistent with past quarters. So rather than go in to those in detail, I'll leave them there for your review and stop here, and we'll go ahead and open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question today will come from Ryan Oatman with SunTrust.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Can you talk about the prospectivity of this Wolfcamp A across your acreage based on what you've seen? And how similar is that zone's prospectivity compared with, say, the Wolfcamp B map that you've published?

Scott D. Sheffield

Yes, the Wolfcamp A is pretty much -- like the Wolfcamp B, it's pretty much our entire 900,000 acres. And the Wolfcamp A, as I mentioned, has the most oil in place of the Wolfcamp member benches. There is a lower Spraberry shale that has more oil in place, which we're in the process of testing over the next several weeks. The Wolfcamp A, if you remember, we've had some good results to the south. We've been focused more on the B. This Wolfcamp A happens to be about 2,000 feet deeper. So a combination of better pressure and staying -- and our frac zone staying pretty much in zone, the entire frac stage -- several stages is probably the reason why we're seeing such great performance. And so, as I said also, we're going to be moving up several more wells in the Wolfcamp A in the northern 600,000 acres by late '13, first half of '14 end of the Q.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then conceptually, how should we think about the Jo Mill versus the lower and middle Spraberry? Do you see those as separate zones that you can target? Or do you think you'll be able to attack some of these with same wellbore, say, with the lower kind of frac-ing up into the Jo Mill?

Scott D. Sheffield

Now there's enough separation between all 3. The middle Spraberry shale, the Jo Mill shale and the lower Spraberry shale, they're both -- all 3 very thick. There's enough separation between all the 3 that we don't anticipate any of the fracs to go into the other zone. So we are using micro-seismic on all of the Spraberry shale tests and we're testing now, so we'll have better results. We're just now in the process of completing and frac-ing some of our first wells in both Martin and Midland County in the next few weeks.

Ryan Oatman - SunTrust Robinson Humphrey, Inc., Research Division

Okay, great. And then one last one for me. Moving the 2 out of the 5 rigs over to Andrews County, can you talk about what has you encouraged there and what zones you plan to target?

Scott D. Sheffield

Yes, the -- we're targeting the -- both the Wolfcamp B and the Wolfcamp D are the primary zones. We do have some leases expiring in the area. That's one of the reasons we're moving over there. They're pretty much on the Andrews/Martin County line. We don't have a large position. If you continue to move west, obviously, the acreage sort of plays out. That's why we don't have a lot of acreage way west of that, but it does set up several thousand acres in Andrews. In addition, it sets up our northern acreage in Martin County.

Operator

Next we hear from Doug Leggate with Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

This is getting all very interesting. I wonder if I could just try a couple of questions, please. The A well is substantially better it looks like than several of the B wells you drilled in the results given so far. Is there anything particular unique about the A in terms of well design? Or are we really just looking at significant upside risk to your type curve guidance?

Scott D. Sheffield

No, I think, again, the job [ph] just told us originally that the A zone has the most oil in place and I think that there's a lot of oil in place. I'm hoping that's the reason why we're seeing the flattening. And so hopefully, the amount of oil in place in the Wolfcamp A is allowing the well to flatten sooner than the other 2 wells. We need more data time. But it looks like it is moving towards that 1 million barrels of oil equivalent. We did not really do anything different. The 2 wells were about 700 feet apart between the 2 Hutt wells. So that's why we're excited about it, and we're going to drill several more.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple of follow-ups, if I can just try these. So you're -- I think if I recollect, you're talking about an average-type curve in the north of 500,000 barrels of oil equivalent. Can you help us just to reconcile that number relative to -- obviously, it's early days, but help us reconcile why you've still got such what looks like a low estimate? And I've got a follow-up please.

Scott D. Sheffield

Yes, as you know, now we only have 3 wells. They're starting to obviously show much higher than the 650,000. As I mentioned, 800,000 to 1 million, so I think we're going to have some pretty good data points really now and the end of the year to officially increase that type curve at some point. Doug, so just be patient with it.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Do you mean the 650,000 or the 500,000 because I think your guidance is still 500,000?

Scott D. Sheffield

Yes, we're showing you the 650,000 and these 3 wells are doing way above the 650,000. So we will be increasing it obviously some time by the end of the year or early next year.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Great stuff. Last one for me, 10,000-foot laterals in the south, is that now a sustainable well design? And I'll leave it there.

Timothy L. Dove

Yes, we've done it many, many times now over, I think, 10 wells. And so accordingly, I think we have no risk in terms of the well design. We're used to doing it now.

Operator

Next is Gil Yang with DISCERN.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Could you guys comment on -- did you see any interference between the A and the B wells? Did the A frac into the B in any way? It doesn't look like it on the production curve.

Scott D. Sheffield

No, almost all the entire frac stayed pretty much in zone on the Wolfcamp A.

Timothy L. Dove

Yes, Gil, one real quick, just one note is that we had that Wolfcamp B well off when we frac-ed the Wolfcamp A well. We've put that Wolfcamp B well back on. It basically came back to its rates before we turned it off. So that's indicative of a noninterference situation.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Sure, great. Was there any indication that frac fluid went from the A well into the B well?

Timothy L. Dove

No.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. Does that suggest -- is the 700-foot distance between the 2, the spacing assuming 140 acres or is it more indicative of maybe 80 acres?

Timothy L. Dove

Well, 700 feet -- it's really you have to look at along the lines of what the depth is, right? These -- the A and the B zones were drilled probably 3 -- somewhere in the neighborhood of 300 to 400 feet difference in depth and 700 feet apart from map view [ph]. So these wells, in that sense, are completely different zones, completely different areas. They're being drilled and completed.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. I understand you're doing the pad drilling to optimize on costs. Is there any hope that you might get synergistic frac-ing if you put the wells closer together?

Timothy L. Dove

Well I think what we're going to see is we'll continue to use zipper fracs as a way to, number one, reduce cost, but also I think the current thinking from our geos and reservoir engineering teams is that zipper fracs can actually potentially lead to a much more complex fracture structure. And so we tend to see when we do zipper fracs from these pads that the well results are better than when you just do one-off completions. And probably, that's what's it's related to. But we're doing a lot of work to understand that question.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Great, all right. And last question for me. Is it -- it seems like you shifted a little bit of activity in terms of the number of wells you're expecting away from the Jo Mill, Spraberry towards more the Wolfcamp drilling. Could you -- maybe about 5 wells out of 15 to 20. Can you just comment on sort of what you're thinking is there?

Timothy L. Dove

I'd say there's no information on that whatsoever. Basically, it's just a matter of which wells are scheduled. It has to do with which wells we can get permitted and built. So there is no information in there at all regarding a choice. It's simply a matter of the way the schedule is playing out.

Operator

Our next question will come from David Kistler, Simmons & Company.

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

Following up a little bit on Gil's question with respect to interval drilling, can you talk a little bit about what your plans are going forward in the north for testing the different intervals and communication between them? Or is over the next, call it, year or 1.5 years really predicated more towards just de-risking individual intervals and then figuring out whether there's communication later?

Timothy L. Dove

Well what you see us doing, if you take a look at some of the minutia on Slide 13 is we're actually testing sort of the notion of whether there is any interference. So if, for example, we're pairing up wells in the Wolfcamp B and D in some circumstances and several of the bars I showed you that we show a Wolfcamp B and D. So we'll know a lot more about spacing on the one hand and then the possibility of interference on the other, which are linked, obviously. But by the same token, we're doing the same thing where we're drilling Jo Mill section, as well as Spraberry section. As you can see in a couple of cases, we have a situation where we drill a Jo Mill and a lower Spraberry; a Jo Mill and -- actually, in a lower Spraberry with a middle Spraberry. So we're actually testing all of these concepts of understanding the nuances associated with which interval we complete within and the effects on other intervals. Right now, we really don't expect anything in the way of interference. We've got such a large section here. You have 3,000 to 3,500 foot of shales here. So we can I think effectively complete in various different intervals without much effect to others.

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

Okay, I appreciate that. And then switching back to the A interval for a moment and your comments on the ability to keep that frac in place. Can you talk a little bit about what kind of learnings took place there. I know that was a challenge you guys were looking to overcome and successfully did on the quarter. But do you feel like you've got the recipe and the confidence dramatically increased for being able to execute that? Any kind of color you can give us around that would be helpful.

Scott D. Sheffield

Yes, I think I'll make one point. We are 2,000 feet deeper than the southern JV area. And secondly, there is a very, very tight formation, the Dean formation, which we have completed vertically over the last 30 years. But it's probably the tightest zone, so it's very, very tight. It's a -- and some of our concerns over the past that do we frac up into the Dean and we're really not frac-ing in the Dean. It's so tight that the A frac pretty much all stayed in zone. So that's highly encouraged.

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

Okay, that's helpful. And mainly because it seems like Permian is stealing the show here. Maybe switch to Eagle Ford just for a moment. Obviously, execution continues to be strong there. Some of your peers have been putting a significantly larger amount of proppant in place and driving pretty staggering production rates. Will you guys be experimenting with that going forward?

Scott D. Sheffield

Yes, we have multiple pilots going on to study various aspects of how to improve the completions. And one of them is, as you said, increasing the amount of proppant used. Also looking at configurations of the number of stages that are pumped and also how we actually perforate within those stages, how many clusters and so on. All that work is being done in a pilot sense. In fact, we started that early this year. We should know a lot about those results by the end of this year. The results look very positive, though, to basically pump more proppant. That's getting pretty clear to us. And so that's, I think, the direction we're going.

Operator

Next is Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Your medium-term growth guidance calls for about 15% midpoint at about a $95 oil price. As we've seen the recoverable resources for Pioneer increase with each successful horizontal test in the Permian, should we think about this increased resource as just providing more years of 15% growth or should we think about upside to that growth rate? And then perhaps you could also add how that dovetails with what we should expect from a CapEx cash flow perspective once the drilling carries run out?

Scott D. Sheffield

Yes, I think that's obviously our target over the next several years, Brian. I think the big upside to it is that we were still not modeling wells coming on 1,600 to 1,800 barrels a day. We were modeling wells in the north coming on 800 to 1,000 barrels a day, IP rates. And so if we -- we need more data before we change that model. Also, we're waiting for the results on the 3 Spraberry zones to the north and then we're going to be reallocating capital to the best returns of these 6 intervals. So we -- at this point in time, we don't know which of the 6 are going to be the best. We know Wolfcamp B and A are very good. So the Spraberry wells are going to have to really perform and be drilled at a lower cost to compete with the Wolfcamp A and the Wolfcamp B. But we'll know all those answers over the next several months. But the key driver and the key upside to move toward a higher growth rate, ignoring commodity prices, is whether or not we change the IP rates and continue to deliver wells coming on 1,600 to 1,800 barrels a day to the north. And that'll be the big swing factor in our long-term growth rate for the company.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great, that's helpful. And then going back to the Wolfcamp A, you highlighted that your expectation in the oil in place for the A zone exceeds the other zones, particularly the B zone. How do we think about that in the context of the 2 Hutt C wells that have been drilled here with similar lateral lengths, in which the 30-day rate from the B well exceeds the A well? I know these are just 2 wells, but do you expect a lower decline coming from the A well and therefore, a higher EUR or just a lower recovery rate? Or is there some greater opportunity for further downspacing within the A?

Scott D. Sheffield

As you can see on Slide #9, the well pretty much averaged both the Mabee well and Martin county, and the Hutt Wolfcamp A well pretty much stayed similar performance below the level of the Hutt Wolfcamp B well. It's -- we only have probably 10 days of data to show that the Wolfcamp A well is acting above these [ph]. So we need more data at this point in time. So if you had asked me 10 days ago, we were putting the Wolfcamp B Hutt well as the best well. So we need more data to see whether or not this Hutt Wolfcamp A well is going to end up doing better.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. Based on -- your hypothesis though, it would be that similar lateral lengths and similar well types will end up with a higher EUR in the A versus the B, assuming you can frac it correctly.

Scott D. Sheffield

Potentially. So it's showing that right now, but we need more data. We need more time.

Operator

Next, we'll hear from Leo Mariani with RBC.

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

Just wanted to focus a little bit on the rig ramp in the northern Midland Basin. You guys are at 5 now. You talked about going to 8 for next year. When would you guys expect to be at 8? Would that be kind of very early next year? And would 8 be more of an average rig count in the north for next year?

Timothy L. Dove

Yes, Leo, I think what we're going to do is have 3 more rigs basically hot on January 1, and that means we'll average 8 for the year.

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

Okay, that's helpful. And in terms of well cost, you guys talked about $7.5 million to $8.5 million. I get a clue [ph] that's kind of where you're at now without science. I mean, where do you think these costs could go over time as you hopefully start drilling a lot more of these and you are able to drill them faster and optimize your pad drilling in your fracs here? What kind of downside do you think there could be to that well cost, assuming, say, flat service costs over the next year or 2?

Timothy L. Dove

Well, one thing I can tell you is in all of these shale plays, you tend to see efficiencies that are brought to bear after -- with time and continuous improvement. Use Eagle Ford as an example where our days on wells have come down dramatically. It's not unusual to see 20% reduction as the number of days on wells. So that's not an exact 20-day -- sorry, 20% effect on total cost because completions also have a big component of that. But the fact is if we're drilling a lot longer laterals also -- we'll also potentially add increased costs. So there's a mixed bag on this answer. It has to do with efficiencies we can wring out of the system, which we'll do in the combination of pad drilling, new completion concepts, but it also be offset to the extent we're going with longer laterals.

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

Okay, that's helpful. And I guess, just going over to the southern Wolfcamp, trying to get a sense of how many non-B zone wells you guys have brought on production at this point?

Timothy L. Dove

I'm going to look around the table and get the answer to that question. How many non-B zone?

Scott D. Sheffield

It's about 5 to 10.

Timothy L. Dove

Right in that area.

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

All right. And I guess, can you maybe just discuss a little bit about the performance of those other zones versus the B in the southern area?

Scott D. Sheffield

Yes, I think most of those, Leo -- in the Wolfcamp A. We have 2 or 3 good wells in the Wolfcamp A. And remember, we had a couple that we frac-ed up. We didn't have 3D seismic. We frac-ed up some faults and then we had a very good lower -- the Wolfcamp B expands to about 600 to 700 feet in the south, and we have some good lower Wolfcamp B wells. And we'll still continue to drill those. We think the Wolfcamp B could be developed with 2 wells.

Timothy L. Dove

Yes, to clarify that point, most of the wells that are being completed in the Wolfcamp B were actually the what we call the Wolfcamp B2 zone. So the deeper B3 is what we're referring to some new concepts for completions, and you're probably heading towards stacked B laterals as we move forward.

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

Okay. And I guess in terms of the A zone, you mentioned that some -- you're frac-ing the faults. One is good, but it sounds like you have some good wells. I mean, do you feel that the A is pretty consistent across your southern acres and those are really just sort of mechanical issues on those couple of wells that weren't as good? And how would you compare to the A to the B results in the south in terms of recoveries?

Scott D. Sheffield

Yes, they're both very similar. We're just trying to make sure that we don't have any of the issues we've had frac-ing in the faults like we've had. So we're making sure we finish the 3D seismic. We're focused on the B now. We're eventually going to drill some D wells in the JV area also. That should be coming up late this year, early next year. So we're still optimistic about the A and the D also. And we'll eventually have a couple of areas with the Wolfcamp C in the JV area also.

Operator

Arun Jayaram, Crédit Suisse, is next.

Arun Jayaram - Crédit Suisse AG, Research Division

Tim or Scott, I was just trying to see if you could help me a little bit with a little bit of a mental picture of the A and B well in the Hutt lease. You mentioned they were drilled about 700 feet apart, but just trying to understand, were the wells essentially drilled parallel to each other?

Scott D. Sheffield

Yes. So the way to think about it, they're essentially 700 feet apart parallel in plan views. So when you look down at the map, they essentially are parallel. But in a depth sense, so obviously, the A is shallower than the B. The A well is drilled somewhere in the neighborhood of 300 to 400 feet above the B well.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And then the first completion, was that in the upper Wolfcamp B?

Timothy L. Dove

When you get up there, the B zone becomes thinner, and by thin, I mean 400 feet. So it's not really thin. It's just not as thick as it is in the south that we were discussing earlier where you have the opportunity for stacked laterals. So the B zone at 400 feet means probably it's one horizontal there and similar thickness in the A.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And Tim, have you put any of the 3 wells yet on pumps yet? And if not, about what timing do -- would you plan to put them on the pumps?

Timothy L. Dove

Well, normally, what we're doing is we're flowing [ph] these wells for a while, then pretty soon thereafter, put them on gas lifts. So these wells are generally speaking -- have been on gas lift. At the point at which the pressures in the well reduced to a point where it makes sense and fluids in the well, we then -- we'll go to basically rod lifts or rod pumps.

Arun Jayaram - Crédit Suisse AG, Research Division

That's helpful. The next one, just as you shift up into Andrews County, how does the geology change? I know it's a little bit northwest of the Mabee well. Does the geology change much as you shift a little bit north?

Scott D. Sheffield

No, we see no change that's why we're moving up there. As Tim mentioned, 15 miles from the Mabee well. We see no change in the Wolfcamp B that we targeted. That's why we're moving up there.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And just my final question, Scott. You had a pretty provocative set of numbers around the Hutt lease. You talked about 11,000 acres and perhaps a 0.5 billion barrels of potential just on 11,000 acres. Could you help us as walk through how you arrived at that math in terms of the different zones and...

Scott D. Sheffield

Yes, I just took -- take 800,000 barrels per zone, 700 locations and 93% net revenue.

Arun Jayaram - Crédit Suisse AG, Research Division

Fair enough. I suspect Mr. Hutt is pretty pleased with those numbers.

Scott D. Sheffield

The Hutt family is very well compensated [ph]. I'm glad it's only a 7% royalty.

Operator

Our next question will come from Charles Meade, Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

If I could bang on the difference a little bit more between the Hutt 1 and the -- or the Hutt 1H and the Hutt 2H. I'm wondering if maybe you can add some detail on what the total fluid you got back in those wells in their early days were? And I guess, what I'm wondering is if perhaps you got more of your frac load more back quickly in the A and that might explain the 30-day rate being lower but the spot rate at 60 day being higher?

Timothy L. Dove

Yes, Charles, this is Tim. I'm going to have to dig out that data. Why don't you call us back and we'll be able to give you more color on that. I simply don't have it here in front of me.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

All right. No problem. Then as a second question, on the -- I mean maybe you guys did this by design, but I noticed you didn't have one of the slides that I was most looking forward to, which showed the one that -- I think, last quarter, you showed the Jo Mill, those 2 Jo Mill laterals and how they had to continue to performing. And I wonder if you could maybe just offer some comments on how those wells are holding up?

Scott D. Sheffield

Yes, they are still holding up just like we had shown before. So no change. We just thought it was old data, so that's why we haven't updated but it's very, very positive.

Timothy L. Dove

Those wells, Charles, are -- actually, it's performing very well, in general, average about 50,000 to 60,000 barrels already produced in about 3/4 of a year or maybe 10 months or so. Now realizing that it was thought in the traditional vertical wells that Jo Mill would produce 20,000 barrels in 40 years. So it just goes to show you and the micro-seismic confirms that we frac-ed up into Jo Mill shale and that's what's leading to the incremental production. But it's about 650 to 60,000 barrels in about 10 months, which is pretty phenomenal. The other thing to know is, Charles, it's short laterals. Those were 2,500-foot laterals. You start [ph] laying out to 5,000-foot laterals, which is the next set of Jo Mill are going to be 5,000-foot laterals. Now you're talking about pretty substantial upside.

Operator

Our next question will come from John Freeman with Raymond James.

John Freeman - Raymond James & Associates, Inc., Research Division

On the Wolfcamp A, I mean, I know internally, you'd always thought that was probably your best zone and the only issue that you all ever thought might face, as Scott alluded to, is the issues with the previous sort of vertical Dean completion. So I just -- just to clarify, Scott, on your comments, it was a nonevent on this recent well and then what you all have done in the south on the 2 or 3 wells that were the A, was that exact same experience that Dean was not an issue?

Scott D. Sheffield

Yes, the Dean wasn't really the issue with the south either. It's really frac-ing up faults before we had 3D.

John Freeman - Raymond James & Associates, Inc., Research Division

Okay, great. And then when I think about what you're doing on the pad drilling side, with the 2-well pads in the north and the 3-well pads in the south, should I sort of assume that next year in the north, that probably moves closer to what you're doing in the south, with like a 3-well pad? And then longer term, should I use kind of what you all have done in the Eagle Ford as sort of the game plan and ultimately, this goes to like 5, 6 wells per pad?

Scott D. Sheffield

Yes, we will be adding more wells to the pad just like we are in the south JV area, probably not as quick starting in early '14, more like late '14 going into '15, '16.

John Freeman - Raymond James & Associates, Inc., Research Division

Great. And then the last question for me, you all have worked down the other vertical frac bank by about 72 wells in the first half of the year. Could you just give me what the absolute number is of the wells that are currently where the vertical frac bank stands?

Timothy L. Dove

That'd be 40, John.

Operator

Michael Hall with Heikkinen Advisors is next.

Michael Hall

I guess, most of mine have been answered at this point. But I guess, just to beat a dead horse to some extent, but just to be clear, in terms of how the 3 wells that are highlighted on Slide 9 were produced and in terms of when they are put on lift and that sort of thing, is there -- were there any material differences in those 3?

Scott D. Sheffield

I think the only thing that you can -- we don't have the exact dates, but you can see on the -- I did mention that the red curve, which is the Wolfcamp A well, we don't know -- their field people don't know the difference of the pickup between the gas lift versus modifying the heater treater. So that's why we need to watch it a little bit longer to see the performance of it. But generally, they're all -- they all 3 start flowing, they go to gas lift and probably, these wells are good enough. They'll probably a good -- I'm guessing 18 months to 2 years before they even consider pumping units.

Michael Hall

Great, that's helpful. Appreciate it. And then on the Spraberry shales, I know -- I think if I recall in the past, you've talked about Jo Mill shale is having somewhat of a limited lateral length to them. Is that the same in kind of all the Spraberry shales or is that really just going to be the Jo Mill?

Scott D. Sheffield

Yes, right now, we're starting out -- we are -- the Spraberry shales are going into a more depleted area. So we have about 18,000 wells as we had mentioned. Most of them have penetrated the Spraberry shales, not perforated the Spraberry shales but have penetrated. So we do have lower pressure. And so most of our wells right now are going at about 5,000 feet, a little bit more than 5,000 feet are Spraberry shales. For the Wolfcamp, we're going out longer, 7,000 to 10,000. But right now, our initial wells are in this 5,000, maybe a little bit higher than the Spraberry shales to start off with.

Michael Hall

Okay. And then is that sort of a natural limit of any sort or might those 5,000-foot laterals move up to 7,000 foot?

Scott D. Sheffield

No, we're being careful. We think we can go out longer over time.

Operator

Next we'll hear from Matt Portillo with Tudor, Pickering, Holt.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just one quick question for me. In terms of the Eagle Ford, just hoping to get a little bit of color on how you guys think about inventory depth, especially with some of the downspacing pilots you're running currently, and then how you think about the acceleration potential or how you feel about your drilling program in the play, assuming that inventory does move up.

Timothy L. Dove

Yes, I think, first of all, you're correct to the extent that some of these areas that we're talking about drilling and testing to 40 acres. To the extent that's successful, which we believe it will be, it will dramatically increase our amount of inventory we have to drill in the future. I will tell you that the inventory we have is somewhat dependent upon how many gas wells we want to drill. Today, we are essentially drilling no dry gas wells. But when it comes to the oilier sections of the play, it could literally add hundreds of wells to the inventory by going to 40-acre spacing.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And as we think about the relative economics of that play and how it competes for capital on a go-forward basis, especially if there is an acceleration case versus the Wolfcamp, could you just give us a little color there and then how we should think about capital allocation?

Timothy L. Dove

Well I think through time, it's clear the Eagle Ford Shale wells -- because of how productive they are, especially earlier in their lives -- are some of our best economics. They were clearly better and then our vertical Spraberry trend drilling economics for some time, and that's why it was the case -- it made sense to move a lot of capital into that play. Now as we look forward to horizontal Wolfcamp drilling, it appears in the early stages that you get a significant amount of capital efficiency from horizontal Wolfcamp and potentially these other zones such that their economics could be as good or even slightly better than the Eagle Ford. But I think the Eagle Ford will always be competitive because you have such prolific wells, such high-rate wells and such high EURs per well that it's always going to be competitive even probably compared to these horizontal wells. Now if you're talking about 1 million barrel wells that are drilling oily prospects compared to, let's say, a more gassy Eagle Ford well, then you'd probably come to the view that the horizontal Wolfcamp wells could exceed the economics of the Eagle Ford.

Operator

Our next question will come from Joseph Allman with JP Morgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So in the southern area, the JV acreage, you mentioned you've got -- you put 22 new wells online and the IP rate was up to a 1,000 barrels a day. What was the average of those 22 wells in terms of IP rate?

Timothy L. Dove

It was about 700 or so, realizing that in this particular quarter, the wells that we put on production had a mix of wells and it had a larger mix than we would normally expect of wells being drilled in the southern part of the acreage and that was an effort to make sure we could hold that leasehold. As you know in the southern part of the acreage, the EURs are lower than they are in the north, and so our average results this quarter were as expected, they were expected to come in on average below last quarter's averages only because of the fact it's the mix of wells we're drilling. And so I think it came in essentially on plan. As we look to the second half of the year, we will be much more heavily focused on northern acreage drilling. So you should get back to more of the higher EURs and/or IPs as you look towards our results in the second half.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

And Tim, when you talk about mix of wells, what characteristics are you talking about?

Timothy L. Dove

Well I'm talking about IP rates and what we think ultimate reserves or resources are going to be per well.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. So in the southern, I think, you're using -- what are you using? 575,000 barrels of oil equivalent for an EUR average? Is that -- so are the wells so far holding up to that?

Timothy L. Dove

Absolutely. I think the question is, again, has to do with the mix of the wells. Some of the areas in the north, of course, where we've drilled the Giddings wells. Those wells clearly are exceeding 650,000 barrels. You go maybe to the various southern part of the acreage, you have maybe something more towards 400,000 or 450,000. So when we say 575,000, it's intended to encompass kind of an average across the whole acreage position, realizing as you go north, the results improve.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. That's helpful. And then just in the play overall, especially in the northern section, how much of your -- how much is lease exploration driving the timing of your drilling?

Timothy L. Dove

Well it's certainly driving a good bit of our timing this year. However, as I mentioned, when we were talking about this during -- going through the slides, we really now heavily heading more towards pad drilling and it will be focused on the north. So the southern drilling really was just that intention to make sure we can preserve the leasehold. As we go forward, very little of the drilling campaign will be directed by lease preservation.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. Because as you do some of that drilling to the northwest of your northern acreage, it seems that some of that acreage is not as blocky as the stuff kind of more in the central and southern parts. So what's the reason for going over there and testing that part?

Timothy L. Dove

Are you talking about the Andrews County or what...

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Yes, I'm talking about Andrews County because that seems less blocky than some of the other acreage you've got. Is that -- is lease exploration driving that drilling?

Timothy L. Dove

Well let me just say this. What we're doing is drilling a well that's basically in western Martin County. I mean it's basically on the line between Andrews and Martin. And what we're doing is we're, in a sense, connecting the dots. So to the extent we drill a good well on this acreage, which we believe we will, then what we do is we prove up that 15-mile corridor up through the northwestern part of Martin County in essence. And so you're right. I mean it is to the western extent of our acreage position, but that's the objective is to connect the dots all the way to the edge of our acreage.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. Okay. And then lastly, just when you look at the whole company and you look at the potential to get to be free cash flow positive. Based on your current plan, when do you see Pioneer becoming free cash flow positive?

Scott D. Sheffield

We have so much opportunity that we can probably just dial in our own growth rate over the next several years. So we're not driving to free cash flow positive. And people that are free cash flow positive, they've got no place to put their great capital. So we have a lot of great assets to invest in especially in the Permian basin and the Eagle Ford. And so it's not a key driver. So it's -- we got -- it's more about bringing forward our NAV and growing the value of the stock. So we can be free cash flow positive anytime, but we're not bringing our NAV forward. So we need -- as I mentioned before, Tim too, we need $300 billion to $400 billion of capital to develop these resources. So we're not focused on the free cash flow at this point in time.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Got you. So does that mean that as you learn more about this play and delineate the play, we're probably going to see further acceleration beyond what you've already described?

Scott D. Sheffield

No, I think that the key driver is whether -- when we change our model to use 1,800 barrel a day IP rates. And that will -- it will set up a whole new growth profile for us over the next several years.

Operator

Rehan Rashid with FBR has a question.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Yes. And most -- all of my questions have been answered, but maybe I'll make up one. How about people? As you kind of develop a business plan into the out years, do you have enough kind of internal people, geologists, everything else in between?

Timothy L. Dove

Yes, Rehan, we've got -- we've built an outstanding team of geoscientists, as well as engineers, over the last several years. I feel very good about that. We're the biggest employer in Midland, which gives us a tremendous operational advantage out there. And people want to work for our company in all of our areas of operation because of our reputation and where we're going with the company. So I think people will be something that we can definitely achieve in terms of growth.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Got it. And remind me the chart you had in the last presentation about total resource potential and recoverable in the Basin, Midland Basin of about $50 billion kind of for the industry and 30% of it for yours. Did that have only 2 of the prospective 6 formations?

Scott D. Sheffield

It did not have the lower Spraberry shale and the middle Spraberry shale. It did not have any downspacing below 140-acre spacing.

Operator

Next we'll take a question from John Wolff, ISI Group.

Jonathan D. Wolff - ISI Group Inc., Research Division

Conceptual question on the northern Midland Basin. Obviously, you're accelerating testing using 2 well pads, testing different zones at the same time. I understand that you need to understand your inventory quickly to know what your company is worth. But as we move out to development mode, which I would imagine is sort of more 2015. Do you see yourself sort of picking one zone that sort of carries 80%, 90% of the drilling? Is one question.

Scott D. Sheffield

Yes, it's actually, right now, we got 2 zones that are pretty close, so Wolfcamp A and the Wolfcamp B. The hardest problem, if we have 6 zones, they're all the same. So what do we pick? So we can only develop so much. But that will be a nice problem to have. But it's hard to predict that yet, John. But right now, we have 2 good zones. We're confident that the Jo Mill will come through. The Rising Star well, a third-party well in Midland County is a very positive well in the lower Spraberry shale. So that's highly encouraging. There's data points on that. So we're starting to get more data points and then at the end of the day, it's going to be hard to pick which of the 6 zones if they're all equal. Hopefully, there'll be some difference in well cost. In the Spraberry Shale, obviously, we hope that comes through because we can drill the wells cheaper long-term. So it's hard to guess at this point in time.

Jonathan D. Wolff - ISI Group Inc., Research Division

Okay. As you look at your acreage to the east in Glasscock, Reagan County, is there any plans to do anything there and what do you think about the prospectivity?

Scott D. Sheffield

Yes, I saw the recent announcement by Energen, that was very positive in Glasscock County. And so we're very highly encouraged by Glasscock County. I think our acreage position is probably 100,000 acres, I'm guessing, give or take 10%. So we haven't moved over there yet. We will. We think it's a tremendous area, and you'll eventually see us move over there.

Jonathan D. Wolff - ISI Group Inc., Research Division

Right. Is it fairly blocked up in terms of being able to drill laterals like you're drilling?

Scott D. Sheffield

Almost all of our acreage is and the reason the acreage in the center part of Midland County, just to let you know, the reason we're staying away from that, we're in the process of working agreements. Those are our units. That's the heart of the Spraberry and probably the heart of the Wolfcamp. And we own anywhere from 2/3 working interest up to 90% working interest in these units and we're working out agreements with the majors. The majors are our partners. And that's the reason you haven't seen a lot of activity in those areas. Once we work out those agreements to start developing, you'll see aggressive drilling done in those areas. That will happen going into '14, '15, '16.

Jonathan D. Wolff - ISI Group Inc., Research Division

Got it. Last one is on the vertical drilling. Can you kind of help us understand -- Energen made the same comment about continuing to drill verticals to hold deeper rights. Is that sort of -- is that the biggest driver of the 15 rigs running? Or is it just nice economics?

Timothy L. Dove

Yes, the economics are good too, John. We've proven that through many multitudes of years. But an ancillary and significant benefit is its ability to control Wolfcamp and other horizontal acreage. And so it's precisely that. We're drilling wells that are economic on the one hand, but we're preserving our horizontal wherewithal in the future.

Jonathan D. Wolff - ISI Group Inc., Research Division

Right. Does that budget have potential to come down from, what is it, $600 million this year?

Timothy L. Dove

It does. I think the way you have to think about it is as we continually ramp up horizontal drilling over the next several years, you could see that a lot of those wells could be targeting areas that we, otherwise, would need to preserve with leasehold drills that would vertical in today's world. So I think you'll see that go down through time. We probably have a window where we need to lease a couple of more years of about 15 rigs, while we build the horizontal rig count. But probably, the window 3 to 5 years from now has us significantly reducing vertical drilling.

Operator

At this time, we have no questions in the queue. I will now turn the conference over to Mr. Scott Sheffield.

Scott D. Sheffield

Again, thanks. We appreciate everybody listening. Great questions. Looking forward to our November call with a lot more results on our program. Again, thanks. Everybody, have a great summer, the rest of summer.

Operator

And that does conclude today's conference call. Thank you for your participation.

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