先鋒自然資源 (PXD) 2013 Q2 法說會逐字稿

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.

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 will provide the financial and operating highlights for the second-quarter of 2013, another strong quarter for Pioneer. He will 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 will 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's Southwest outstanding publicly-held units in exchange for Pioneer common stock. Pioneer is waiting to hear from the Conflicts Committee on the 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 will turn the call over to Scott.

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,176 -- 177.6 thousand barrels a day equivalent. We are 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 of 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 or $0.03 or $0.04, before we see ethane rejection stop.

We are narrowing our production growth guidance range from 12% to 16%, to 14% to 16%. We are tightening that range. Again, very important, in our northern Spraberry/Wolfcamp horizontal drilling program, we are announcing our first Wolfcamp A. If you remember, we are about 2,000 feet deeper in this area, very highly successful. It is 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 30 day average rate of 11 -- 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 of 1,572. Again, a new 30 day average production rate of 10,040 with 76% oil.

We had cumulative production from the first Wolfcamp B interval well, the Hutt well in Midland County. What is interesting, in six months it has reached 140,000 barrels of oil equivalent. If you remember, our typical Wolfcamp, Spraberry/Wolfcamp vertical well takes 30 to 35 years to produce 140,000 on a vertical well. So we did that in six months. What is also interesting, in our Hutt lease, which is becoming very popular for us, it is made up about 11,000 acres, 93% net revenue with 700 potential locations and six intervals, at about 800,000 barrels, at could eventually yield a 0.5 billion barrels, just that lease of 11,000 acres net to Pioneer.

Turning to slide number 4, additional highlights. If you remember, we did increase from one rig to five rigs in the second-quarter in the northern Spraberry/Wolfcamp drilling program. Those additional four rigs are primarily late in the second-quarter. We are currently drilling multiple zones, both the Wolfcamp, Jo Mill and Spraberry shales. In addition, we are moving on two 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 queue for late 2013 and early 2014. We now have five horizontal wells in production in the north. That includes our two Jo Mill wells which are in the Giddings area. We have six wells awaiting on completion, and five wells currently drilling. So it is pointing toward somewhere between six 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 at 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 are still continuing to lower well cost. As we have mentioned before, we were targeting 7,000 foot laterals. We are 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 a 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, for the last three weeks we have significantly increased our hedge positions for finishing up '14, up to 60% in 2015, and from zero really up to 15% in 2016. And we are continuing to move these coverage ratios up, especially in both '15 and '16 as we speak. Again, primarily useing in three 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 the end of second-quarter.

Slide number 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 is being funded with cash flow. We are using as a $95 oil and $4 gas the rest of this year. Obviously, we are seeing higher prices now, but generating cash flow of $2.3 billion, and again with $700 million in cash on hand.

Going to slide number 6, in regard to our production growth. We are narrowing our guidance range from $175 million to $181 million, to $177 million to $181 million. Also, we are bringing out both third- and fourth-quarter. We will see a significant jump in fourth-quarter, primarily due to the fact that the timing of POPS from pad drilling -- we are doing pad drilling in Eagle Ford, pad drilling in our southern JV with Sinochem, and also we are doing pad drilling in the north. In addition, we started our last four rigs in the north late second-quarter, so we won't see the impact of those until late third, or primarily fourth-quarter. And that is why you are seeing a big jump, $185 million to $195 million range for the fourth-quarter of 2013. Again, 62% liquids, moving towards 70% liquids in 2015.

Slide number 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 at 93 going to 142 in 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 in ethane rejection going into the third-quarter. Slide number 8. Again, the two highlights in yellow is the Hutt A well, Wolfcamp A well coming on at over 1,700 barrels a day, located right next to the Wolfcamp B well that has produced over -- about 140,000 in six months. Again, that is 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 -- and we are about 2,000 feet deeper, but it opens up potentially the entire Midland County and Morgan County. Again, for that Wolfcamp A interval. 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 two years ago.

I am looking at slide 9. What is interesting, is the decline curve on these three wells. Both the two Wolfcamp B wells in Martin and Midland, and then the recent Wolfcamp A well. What is interesting is that the Wolfcamp A well is starting to exceed the potential decline of the original Hutt well, Wolfcamp B that has just made 140,000 barrels. A couple things have happened. We have modified our heater treater, and then secondly to reduce back pressure, and then secondly we just recently installed it on a gas lift. So we generally anticipate a slight bump. So it will be interesting to watch, but it is moving past the curve. These three wells are way exceeding, way above the 650,000-barrel type curve, pointing towards similar between 800,000 and 1 million barrels for each of these three locations.

Finally, slide number 10. In summary, again we have a tremendous asset base. We have over 9 billion barrels. We will 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 horizontal Spraberry/Wolfcamp plays. We have a great growth profile of 15%-plus over the next several years. Vertical integration, this is substantially improving execution and returns, great hedge position over the next three years, and again, a great balance sheet. Let me turn it over to Tim to give you more details.

Thanks, Scott. I am 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. And you have heard some of that from what Scott had to say. And the next three slides I am going to cover, provide great deal of granularity on our plan moving forward. We tweak our current plan slightly. The plan still is to spud 30 to 40 wells this year in six different intervals. Each of these intervals we believe are prospective on, plus or minus or even in some cases more than 600,000 acres. The current plan as shown on the slide, is to drill about -- or to spud about 20 to 25 wells in the Wolfcamp, the D, B, and A zones.

And while at the same time, we will 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 five rig campaign, targeting -- spudding those 30 to 40 wells in six different zones. Costs have been coming in at about $7.5 million to $8.5 million in the north, for a 7,000-foot laterals. Of course, it is deeper in the north than it is in the south. We continue to spend money, in the sense of science and facilities for these new wells. That is to say microseismic in most every case, drilling pilot holes, taking cores, and using sophisticated log suites, the idea being gathering data so that we progress into appraisal, we will have all of that behind us.

Turning now to slide 12. The map here shows the general areas we are going to be drilling, and specifically they are 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 two rigs will be heading up there. It is about 15 miles northwest of the Mabee horizontal well in Martin County. Specifically though, going forward we will have three rigs focused on Wolfcamp shale drilling in Midland and Martin counties, and two rigs focused on Jo Mill and Spraberry shales in those same countries. And then after that, we will be moving two of those rigs during the third-quarter to drill Wolfcamp and 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 the 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. This leads to -- as you know, when you look at the rest of our peers, we are in a similar situation with pad drilling. It leads to a relatively lumpy production profile, which we are depicting later in my presentation. But suffice it to say, we are well on the way to executing this $400 million program for this year, and looking at adding three 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 am 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. We expect to add about 20 new wells on production in the second half of year. Again, a lot of that is back-weighted towards the fourth-quarter as you can see. Each of these bars represent two wells. As you can see, for example, the Wolfcamp B and D, that is two wells over a couple quarters being drilled. You see on the lower part of the graph, we have about six wells. So that is three 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 currently, the thinking is we would have a minimum of six wells on production, just again due to the effect of pad drilling. And so, out of the 20, you will see more information as we get into the first quarter. And it is very clear to me, we will 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 seven 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 a 1,000 BOE per well, and very high oil content importantly. We have already mentioned the fact that slickwater effects -- 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 are seeing benefits to reduce costs, whether we used 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 seven rigs this year to 10 rigs next year and so on, increasing after that. We are 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, and maybe slightly over 20, that we will be drilling in 2013, to somewhere in the neighborhood of 10,000 feet. The economic still support this lengthening in a significant way, with about a 20% increase in costs, generating a substantial increase in the EURs, estimated to be somewhere in the neighborhood of 40% to 60%.

And we will be doing about 70% pad drilling in the south. Typically, it is three wells in the south, and that puts your spud to POP length out to about 150 days. Again, you expect to see as result of that lumpy production growth as we get into the third and fourth-quarter, with a lot of the production increases skewed into the fourth-quarter. A real important note here, although we don't give a lot of information on, is the fact that we are testing down spacing, using staggered interval drilling in both the upper B and lower B. All of the resources that are discussed in our Investor Relations material are based on a 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 are testing it as we speak. We will have much more to say about that, over the next couple of quarters.

Now slide -- 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 retention Scott mentioned. But the fact is that we are tightening our range to the upside for 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 [Pryer]. 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 are 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 a minimal levels, having put about 90 wells on production. Almost every single one of those wells will be deepened to the Strawn and 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 for 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 on the exact timing of bringing wells on production.

Turning to slide 16. The Eagle Ford Shale now is effectively a well-oiled machine for Pioneer. You can see 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 was 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 are that much more further advanced, in terms of development here after now being in play three to four 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 costs, somewhere in the neighborhood of $600,000 to $700,000 per well.

It has becoming a recurring theme that, for the third time I will tell you we will see some lumpy production growth as a result of that, as we substantially ramped up our pad drilling. And you can see our production in the fourth-quarter will be growing, because the number of wells we popped at the end of the third-quarter and fourth-quarter will increase, compared to earlier in the year. As I have also mentioned in the southern Wolfcamp, we are also testing down spacing in the Eagle Ford. Our original planning on the Eagle Ford had us about 115-acre spacing. We are now testing 40-acre spacing, especially in some of the more oily areas. We will have more to say about that, after we get the results in the next couple of quarters. And we are 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 are 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 have substantially reducing our frac costs. Now the estimate is over $1 million savings by directing white sand to completions. Well costs have well-stabilized in the neighborhood of $7 million to $8 million. So I am 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 future performance that will be very solid. With that, I am going to pass it over to Rich for a review of the second-quarter financials and third-quarter outlook.

Thanks, Tim. I am going to start on slide 17. Net income attributable to common stock for us was $37 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 recognized on that transaction when it closed at the end of May. So adjusting for those items, we are at $154 million or $1.10 per diluted share. Looking at the middle of the page, where we show our second-quarter guidance, and then the results, how they actually came out. You will see that we are within guidance on all the items, or on the positive side of guidance. As you scan down there, you will see that. I am not going to go through those, but they are there for your review.

Turning to slide 18, price realizations. You will see that our oil price realization improved by 3% relative to the first quarter, up $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, butanes and natural gasoline prices coming down during the quarter. And then, as you are aware -- gas prices were up 19%. Looking at the bottom of the 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 are 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, 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 $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 an 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 pad drilling. So that is there. The rest of these items are very consistent with past quarters, so rather than going through those in detail, I will leave them there for your review, and stop here. And we will go ahead and open up the call for questions.

Thank you.

(Operator Instructions)

Our first question today will come from Ryan Oatman with SunTrust.

Congratulations on these results.

Thanks, Ryan.

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

Yes, the Wolfcamp A is pretty much -- and like the Wolfcamp B, it is 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 are in the process of testing over the next several weeks.

Wolfcamp A, if you remember we had some good results to the south. We have been focused more on the B. This Wolfcamp A happens to be about 2000 feet deeper. So a combination of better pressure, and staying in our frac stands pretty much in zone, the entire frac stage -- several stages is probably the reason why we are seeing such great performance.

And so, as I said also we are going to be moving up several more wells in the Wolfcamp A in the northern 600,000 acres by late 2013 first half of 2014 into the queue.

Okay, thank you. And then, conceptually how should we think about the Jo Mill versus the lower and middle Spraberry. Do see those as separate zones that you can target, or do you think you will be able to attack some of these with the same well bore say, with the lower kind of fracking up into the Jo Mill?

No, there is enough separation in between all three, the middle Spraberry shale, the Jo Mill shale and the lower Spraberry shale. They are both -- all three are all very thick. There is enough separation between all three that we don't anticipate any of the fracs to go into the other zone.

So we are using microseismic on all of these Spraberry shale tests, and we are testing now so we will have better results. We are just now in the process of completing and fracking some of our first wells in both Martin and Midland County in the next few weeks

Okay, great. And one last one for me. Moving 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?

Yes, the -- we are targeting both the Wolfcamp B and the Wolfcamp D, are the primary zones. We do have some leases expiring in the area. That is one of the reasons we are moving over there. They are pretty much on the Andrews Martin County line.

We don't have a large position. If you continue to move last, the acreage sort of plays out, that is what 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.

Thank you for all that color. Congrats again.

Next we will hear from Doug Leggate with Bank of America.

Hi, good morning, everybody. 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 that than several of the B wells you have drilled and the results you have announced so far. Is there anything particularly unique about the A, in terms of well design, or are we just really looking at significant upside to your type curve guidance?

No, I thing again, the geologist just told us originally that the A zone has the most oil in place. And I think that there is a lot of oil in place. I am hoping that's the reason why we are 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 two wells.

We need more data time, but it looks like it is moving toward that 1 million barrels of oil equivalent. We did not really do anything different. The two wells were about 700 feet apart between the two Hutt wells. And so, that is why we are excited about it, and we are going to drill several more.

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

Yes, as you know now we only have 3 wells. They are starting to obviously show much higher than the 650. As I mentioned 800,000 to 1 million, so I think we are going to have some pretty good data points between now and the end of the year to officially increase that type curve at some point. So --

(Multiple Speakers). Did you mean, the 650 or 500, because I think your guidance is 500.

Yes, we are showing you 650. And these 3 wells are doing way about the 650. So we will be increasing it obviously sometime by the end of the year, early next year.

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

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

Great stuff, thanks.

Next is Gil Yang with DISCERN.

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

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

Okay. Are you optim --

Yes, Gil, well, real quick, just one note is we had that Wolfcamp B well off. When we fracked Wolfcamp A well, we put that Wolfcamp B back on, it basically came back right to its rates before we turned it off. So that is indicative of a noninterference situation.

Sure, great. Thanks, Tim. Was any indication of frac fluid one from the A well into the B well?

No.

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

Well, 700 feet is -- well, you really have to look at it along the lines of what the depth is, right? The A and the B zones were drilled somewhere in the neighborhood of 300 to 400 feet difference in depth. And 700 feet apart from that view. So these wells are, in that sense are completely different zones, completely different areas that are being drilled and completed.

Okay. I understand that you are doing the pad drilling to optimize on costs. Is there any hope that you might get synergistic fracking if you put the wells closer together?

Well, I think what we are going to see, as we continue to use zipper fracs as a way to, number one, reduce costs. But also, I think the current thinking from our geos and the reservoir engineering team 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 do one-off completions. And probably, that is what it is related to, but we are doing a lot of work to understand that question.

Great. All right. And last question for me is, it seems like you shifted a little bit of activity in terms of the number of wells you are expecting away from the Jo Mills 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 your thinking is there?

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

Okay, terrific. Thanks.

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

Hi. Following up 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 communications between them? Or is over the next, call it year or 1.5 year, predicated more towards just de-risking individual intervals? And then figuring out whether there is communication later?

Well, what you see us doing, if you take look at some of the minutiae on slide 13, is we are actually testing the notion of whether there is any interference. So for example, we are pairing up wells in the Wolfcamp B and D in some circumstances. And in several of the bars I showed you, that we show a Wolfcamp A and B. And so we will know a lot more about the spacing on the one hand, and then the possibility of interference on the other, which are linked obviously.

But by the same token, we are doing the same thing. We are drilling Jo Mill section as well as Spraberry sections. You can see in a couple of cases we have a situation, where we drill a Jo Mill and a lower Spraberry, and Jo Mill and actually at lower Spraberry with a middle Spraberry. So we are 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 don't really don't expect anything in the way of interference. We have such a large section here. You have 3,000, 3,500-foot of shales here. So we can, I think effectively complete in various different intervals without much effect to others.

Okay. 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 were looking to overcome, and successfully did on the quarter.

But do you feel like you have 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.

I would 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 is probably the tightest zone, so it is very, very tight.

And some of our concerns over the past, do we frac them in the Dean? And we are really not fracking in the Dean. It is so tight, that the A frac pretty much all stayed in zone. So that is highly encouraging.

Okay. That is helpful. And mainly because it seems like Permian is still in 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 propant in place, and driving pretty staggering production rates. Will you be experimenting with that going forward?

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 propant used.

Also looking at configurations of the number of stages that are pumped. And also how we actually perforate within the stages, how many clusters and so on, all of that work is being done in a pilot sense. And 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 propant. And that is getting pretty clear to us, and so, that is I think the direction we are going.

Great. Well, I appreciate that. I will let somebody else jump on. Thanks.

Next is Brian Singer with Goldman Sachs.

Thank you, good morning.

Good morning.

Your medium term growth guidance calls for about 15% midpoint at about a $95 oil price. As we have seen the recovery resource 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 can also add how that dovetails with what we expect from a CapEx cash flow perspective, once the drilling carries around.

Yes. I think, that is obviously our target over the next several years, Brian. I think the big upside to it, is that we are still not modeling wells coming on 1,600 to 1,800 barrels a day. We are modeling wells in the north coming on 800 to a 1000 barrels a day IP rates. And so if we -- we need more data before we change that model.

Also we are waiting for the results on the three Spraberry zones to the North. And then we will be reallocating capital to the best returns of these six intervals. So we, at this point in time we don't know which of the six are going to be the best.

We know Wolfcamp B and Wolfcamp A are very good. So the Spraberry wells are really going to have to perform and be drilled at a lower cost to compete with Wolfcamp A and the Wolfcamp B. But we will know all those answers over the next several months. But the key driver and the key upside to move towards a higher growth rate, ignoring commodity prices, is whether or not we change the IP rates and continue to deliver wells coming in on 1,600 to 1,800 barrels a day to the North. And that will be the big swing factor in our long-term growth rate for the Company.

Great. That is helpful. And going back to Wolfcamp A, you highlighted that your expectations with the oil in place for the A zone exceeds the others, on 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 two 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.

As you can see on the slide number 9, the well pretty much averaged, both the Mabee well in Martin County and the Hutt Wolfcamp A well pretty much stayed similar performance, below the level of the Hutt Wolfcamp B well. We only have probably 10 days of data, to show that the Wolfcamp A well it is acting above these. 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.

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?

Potentially. It is showing that right now, but we need more data. That is what I -- need more time.

Okay, great. Thank you.

Next we will hear from Leo Mariani with RBC.

Hi, just wanted to focus on the rig ramp in the northern Midland basin. You are at 5 now. You have talked about going to 8 for next year. When would you 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?

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

Okay, that is helpful. And in terms of well costs, you talked about $7.5 million to $8.5 million. I guess that is where you are at now without science. Where do you think these costs could go over time as you hopefully start drilling a lot more of these, and are able to drill them faster and optimize your pad drilling and 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 two?

Well, the one thing I could tell you is, in all of the shale plays you tend to see efficiencies that are brought to bear after -- with time and continuous improvement. Use Eagle Ford as an example, of where our days on wells have come down dramatically. It is not usual to see 20% reductions in the number of days on wells. So that is not an exact 20 day -- or sorry, 20% effect on total costs, because completions also have a big component of that.

But the fact is, if we are drilling a lot longer laterals also, we will also potentially add increased cost. So there is a mixed bag on this answer. It has to do with efficiencies we can wring out of the system, which we will do, and the combination of pad drilling, the new completion concepts. But it will also be offset to the extent, we are going with longer laterals.

Okay. That is helpful. And just going over to the southern Wolfcamp, trying to get a sense of how many non-B zone wells you have had brought on production at this point?

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

(Multiple Speakers). About five to ten, right in that area, yes.

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

Yes, I think most of those Leo, were -- in the Wolfcamp A. We have two or three good wells in the Wolfcamp A. And remember, we had a couple that we fracked up -- we didn't have 3-D seismic, we fracked 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 will still continue to drill those. We think the Wolfcamp B could be developed with 2 wells.

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

Okay. And I guess, in terms of the A zone, you mentioned that some fracs in the fault weren't so good, but it sounds like you have some good wells. Do feel like the A is pretty consistent across your southern acreage, and those were really just mechanical issues on those couple wells that weren't as good? And how would you compared to the A -- the B results in the south, in terms of recoveries?

Yes, they are both very similar. We are just trying to make sure that we don't have any of the issues we have had of fracking into faults like we've had. So we are making sure we finish the 3D seismic, and we are focused on the B now. We are 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 are still optimistic about the A and D also. And we will eventually have a couple areas with Wolfcamp C in the JV area also.

Okay, thanks.

Arun Jayaram, Credit Suisse is next.

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

Yes. So the way to think about it, they are essentially 700 feet apart parallel, in planned views. And we look down at the map, they essentially are parallel. But in a depth sense though, obviously, the A is shallower than the B. The A well is drilled about 300 feet to 400 feet above the B well.

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

When you get up there the B zone becomes thinner.

Okay.

And by that I mean, 400 feet. So it is not really thin, it is just not as thick as it is in the south, that we were discussing earlier where you have opportunity for stacked laterals. So the B is on at 400 feet, it means probably it is one horizontal there, and similar thickness in the A.

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

Well, normally what we are doing is, we float the wells for while then, and pretty soon thereafter put them on gas lifts. So these wells have, generally speaking, been on gas lift. At the point at which the pressures in the well are reduced to a point where make sense, and fluid -- fluids in the well, we will then go to basically to rod lifts or rod pumps.

Helpful. Next one, just as you shift up into Andrews County, how does the geology change? I know it is a little bit north -- north west of the Maybee well. Does the geology change much as you shift a little bit north?

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

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 0.5 billion barrels of potential just on 11,000 acres. Could you help us walk through how you arrived at that math, in terms of the different zones? And --

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

Fair enough. I suspect Mr. Hutt is pretty pleased with some of those numbers. Thanks a lot. (Laughter).

The Hutt family is very well -- (Laughter).

All right, take care.

I am glad it is only a 7% royalty.

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

Good morning, and thanks for taking my question. If I could bang on the difference a little bit more between the Hutt 1 and the -- or the Hutt 1H and Hutt 2H. I am wondering if you can add some detail on what the total fluid you got back in those wells in the early days were?

And I guess, what I am wondering is if perhaps you have got more of your frac load more quickly in the A? And that might explain the 30 day rate being lower, but the spot rate at 6 day being higher?

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

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

Yes, they are still holding up, just like we had showed before. So no change. We just thought it was old data. So that is why we have not updated it, but very, very positive.

Okay, thank you very much.

Those wells, Charles, are actually performing very well. They have -- in general average about 50,000 to 60,000 barrels already produced in about three quarters of a year, or maybe 10 months or so. Realizing that it was thought in a traditional vertical well, the Jo Mill would produce 20,000 barrels in 40 years.

So it just goes to show you, and the microseismic confirms it, we fracked up into the Jo Mill shale. And that is what is leading to incremental production. But it is about 650 to 60,000 barrels in about ten months, which is pretty phenomenal.

Got it. And that is great detail. And just --

(Multiple Speakers). That other thing to know, Charles, is those are short laterals, those are 2500-foot laterals.

Right.

Playing out to 5000-foot laterals, which is the next set at Jo Mill are going to be 5000-foot laterals. Now you are talking him about pretty substantial upside.

That is what I was after Tim. Thank you for that detail.

Yes.

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

Good morning.

Good morning.

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

Yes, the Dean wasn't really the issue, the south either. It was really fracking up faults before we had 3D.

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

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 2014, more like late 2014, going into 2015 and 2016.

Great. And then the last question for me, you all have worked down the vertical frac bank by about 72 wells, 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?

That would be 40, John.

Great. Thanks a lot, congratulations.

Michael Hull with Heikkinen Advisors is next.

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

I don't think the only thing that you can -- we don't have the exact dates, but what you can see on the -- I did mention that the red curve which is the Wolfcamp A well. We don't know -- the field people don't know the difference of the pickup between the gas lift versus modifying the heater treater. So that is why we need to watch it a little bit longer to see the performance of that.

But generally, -- they all three start flowing. They go to gas lift. And these wells are good enough, that it will be a good, I am guessing 18 months to 2 years before they even consider pumping units.

Great, that is helpful. I appreciate it. And then on the Spraberry shales -- I know, I think if I recall in the past you have talked about the Jo Mill shale 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 Jo Mill?

Yes. Right now we are 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 has penetrated Spraberry shales, not perforated the Spraberry but have penetrated, so we do have lower pressure.

And so we are -- most of our wells right now are going out about 5,000 feet, little bit more than 5000 feet, our Spraberry shales. So for the Wolfcamp, we are going out longer 7,000 to 10,000, but right now our initial wells are in the 5,000 maybe a little bit higher on the Spraberry shale to start off with.

Okay. And is that sort of a natural limit of any sort, or might those 5000-foot laterals move up to 7,000-plus intervals?

(Multiple Speakers).We are just being careful, we think can go longer over time.

That does it for me. Appreciate it, thanks.

Next we will go Matt Portillo with Tudor, Pickering & Holt

Good morning. So one quick question for me. In terms of the Eagle Ford, just hoping to get a little bit of color on how you think about inventory depth, especially with some of the downspacing pilots you are 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?

Yes. Well, I think first of all, you are correct to the extent that some of these areas that we are talking about drilling and testing to 40 acres, to the extent that is 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 a 40-acre space.

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 how we should think about capital allocation?

Well, I think through time, it is clear the Eagle Ford shale wells because of how productive they are, especially early in their lives, have been 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 significant amount of capital efficiency from horizontal Wolfcamp, and potentially these other zones, such as their economics could be as good or 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 is always going to be competitive, even probably compared to these horizontal wells.

Now if you are talking about 1 million-barrel wells, they are drilling oily prospects, compared to let's say more gassy Eagle Ford well. Then you would probably come to the view that the horizontal Wolfcamp wells could exceed the economics of Eagle Ford.

Thank you very much.

Our next question will come from Joseph Allman with JPMorgan.

Thank you. Hi, everybody. So in the southern area, the JV acreage, you mentioned you have 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?

It was about 700 or so. Realizing that, in this particular quarter, the wells we put on production had a mix of wells. And it had a larger mix than we would normally expect on 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 is the mix of wells we are drilling. 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 those results in the second half.

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

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

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

Absolutely. I think the question is, again has to do with the mix of wells.

Some of the areas here is the North, of course, where we drilled Giddings wells, those wells clearly are exceeding 650,000 barrels. You go maybe to the very southern part of the acreage, you have maybe something more towards 400,000 or 450,000. So when we say 575,000, it is intended to encompass an average across the whole acreage position, realizing as you go north the results improve.

Okay, that is 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?

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

Okay. 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 a central and southern part. So what is the reason for going over there, and testing that part?

Are you talking about Andrews county? Or what -- (Multiple Speakers).

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

Well, let me just say this. What we are doing is drilling a well that is basically in Western Martin County. I mean, it is basically on the line between Andrews and Martin. And what we are doing is, is we are in a sense connecting the dots.

So to the extent we drilling good well on this, which we believe we will. Then what we do is prove up that 15-mile corridor up through the northwestern part of Martin County in essence. And so, you are right. I mean, it is to the western extent of our acreage position. But that is the objective is to connect the dots all the way to the edge of our acreage.

Got you. Okay. Then lastly, 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?

We have so much opportunity that, we can probably just dial in our own growth rate over the next several years. So we are not driving to free cash flow positive. And people that are free cash flow positive, they have 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 is not a key driver.

And so, we got -- it is more about bringing forward NAV, and growing the value of the stock. So but we can be free cash flow positive anytime, but we are 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 are not focused on free cash flow at this point in time.

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

No, I think the key driver is whether -- when we change our model to use 1800-barrel a day IP rates. That will set up a whole new growth profile for us, over the next several years.

Okay. Fair enough. Thank you.

Rehan Rashid with FBR has the next question.

Most -- well, all of my questions have been answered, but maybe I will make up one. How about people, as you kind of develop a business plan into the out years, do we have enough kind of internal people, geologists, everything else in between?

Yes, Rehan. We got -- we built an outstanding team of geoscientists, as well as engineers over the last several years. I feel very good about that.

We are 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 are going with the Company. So I think people will be something we can definitely achieve in terms of growth.

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 two of the prospective six formations?

It did not have lower Spraberry shale, and middle Spraberry shale did not have any down spacing below 140 acre spacing.

Got it. Got it. Okay. Thank you, congrats.

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

Hi. Conceptual question on the northern Midland basin. Obviously, you are 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 if -- as we move out to development mode, which I imagine is sort of more 2015, do you see yourself picking one zone own that sort of carries 80% or 90% of the drilling, is one question?

Yes, it looks to me right now, we got two zones that are pretty close, so Wolfcamp A and the Wolfcamp B. The hardest problem, if we have six zones, there are all the same. So what do we pick?

Right.

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 got two good zones. We are confident that the Jo Mill will come through. The Rising Star well, the third-party well in Midland County is very positive well in the lower Spraberry shale. So that is highly encouraging that there is data points on that. So we are starting to get more data points, and end of the day, it is going to be hard to pick which of the six zones, if they are all equal.

RIght.

Hopefully, there will be some difference, I mean, well costs in the Spraberry shale, obviously we hope that comes through, because we can drill the well cheaper long-term. So it is hard to guess at this point in time.

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

Yes, I saw the recent announcement by Energen that was very positive in Glasscock County. And so, we are very highly encouraged by Glasscock county. Our acreage position is probably 100,000 acres I am guessing, give or take 10%.

So we haven't moved over yet, we will. We think it is a tremendous area, and you will eventually see us move over there.

Great. Is it fairly blocked out, in terms of being able to drill laterals like you are drilling?

Most 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 are staying away from that, we are in the process of working agreements. Those are our units. That is the heart of the Spraberry and probably the heart of the Wolfcamp.

And we own anywhere from two-thirds working interest up to a 90% working interest in these units, and we are working out agreements with the majors. The majors are our partners. And that is the reason you haven't seen a lot of activity in those areas.

Yes.

Once we work out those agreements to start developing, you will see aggressive drilling done in those areas. That will happen going into 2014, 2015, 2016.

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

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

Right. Does that budget have potential to come down from the $600 million this year?

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

Got it. That is all for me. Thank you.

Thank you.

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

Again, thanks. We appreciate everyone 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 the summer.

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