先鋒自然資源 (PXD) 2013 Q3 法說會逐字稿

Welcome to Pioneer Resources third quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the internet at www.pxd.com. Again, the internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Earnings and Webcast.

This call is being recorded. A replay of the call will be archived on the internet site through November 30.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time for opening remarks, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please, go ahead.

Good day, everyone, and thank you joining us. Let me briefly review the agenda for today's call. Scott will be the first speaker. He's going to provide the financial and operating highlights for the third quarter of 2013, another quarter where Pioneer delivered a number of significant accomplishments. 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 Shale play, across Pioneer's extensive northern Spraberry/Wolfcamp acreage position.

After Scott concludes his remarks, Tim will discuss our drilling plans in the northern Spraberry/Wolfcamp, the southern Wolfcamp joint venture area and Eagle Ford Shale. He will also comment on our recent successful downspacing activity in the southern Wolfcamp joint venture another and the Eagle Ford Shale. Rich will then cover the third quarter financials in more detail and provide earnings guidance for the fourth quarter. After that, we will open up the call for your questions.

Before moving on with the call, however, there is one procedural item I need to cover. In August, we announced that we entered into a merger agreement related to the acquisition of all of Pioneer Southwest's outstanding publicly held units in exchange for Pioneer common stock. We filed a registration statement with the SEC related to the merger. Because the registration statement is not yet effective, we will not be able to discuss the transaction during the call. We can say that we still expect it to close by the end of this year.

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

Thank you, Frank. Good morning. Third-quarter adjusted income of $176 million or $1.26 per diluted share, on slide number 3. We had third-quarter production 173,000 barrels of oil equivalent per day. Excluding ethane rejection, 174,000 barrels of oil equivalent per day.

We're slightly below guidance primarily due to pad drilling delays, getting wells on production, shutting in some of the offset wells in the Eagle Ford Shale area, which lead to a deferral of about 3,000 barrels a day equivalent. Also, to remind everybody, the third quarter was impacted by the conveyance of the production to Sinochem as part of the JV agreement.

What's most important is the horizontal Wolfcamp Shale production continues to grow. We're going to end up the year approximately 14%, 2013, primarily reflects the effects of pad drilling in Eagle Ford and then also primarily in west Texas. Most of the Wolfcamp was primarily what I call a science year. Also reflects the announced Alaska divestiture as discontinued operations.

Getting into well results, obviously, we're very excited about the Wolfcamp D, or what a lot of people call it the Cline play. We've extended it out 50 miles out to the west and to the northwest. Starting off with our O'Daniel well, which just came on about five, six days ago. IP over 3,000 barrels a day, 3156, 69% oil. Highest IP rate for any interval in the Midland Basin to date.

A well that already has a 30-day production rate, our Hutt C well, where our previous Wolfcamp A and B wells have been drilled and producing, we had an IP rate of 2,128 and a 30-day of a rage rate of 856, 69% oil. We are seeing, due to about 5% to 6% less oil, obviously more gas in these D wells, primarily due to a little bit more mature leading to a little bit more gas, rich gas.

Thirdly, the Scharbauer well had an IP of 1,509, 60% oil, 30-day average of 662. I'll talk more about where we think the estimates are, of long-term tight curves could be for these three wells in a later slide. Obviously, we're excited about the D. It puts it in regard to a development mode play in addition to the successful B and A wells.

Going into slide number 4, enough data on the Wolfcamp B intervals. Again, we had a successful Hutt well. Turns out its the highest IP rate in the Midland Basin of date, 2,227 barrels of oil equivalent per day, with a peak 30-day average rate of almost 1,100 barrels a day, about 75% oil.

In addition, we moved up to a well that is fairly close to our Mabee well. It had an IP rate of 979. What's interesting about this well, it didn't have the high peak you'll see later in the tight curve, but it's been flat and 74% oil. It looks like it will be very, very similar to the other good wells, producing a lot more water.

Again, all of these wells, especially the wells with several months of production data, obviously, we are moving to the EUR for a general area going from the Mabee well all the way down to the Giddings' well, which is a large area, the southern half of Martin County, Midland County, upper part of Upton county. We feel like this area will expect to average 800,000 barrels of oil equivalent or exceed.

People were expecting for results from the lower Spraberry Shale and then also the Jo Mill wells. They just came on production over the last week. It takes about 30 to 45 days for these zones to peak. We do not anticipate giving out results in these wells until February.

We have 13 horizontal wells in production with 3 of these wells flowing back, 7 wells awaiting completion, another 5 wells currently drilling with the 5 rigs. We're running five rigs now. As we mentioned earlier, we'll be adding three more rigs. Obviously, we're continuing to test the various zones. Actually, we'll be drilling early next year a Middle Spraberry Shale well, where we saw recently that Diamondback announced a successful well in the Middle Spraberry Shale.

We expect to increase to 10 plus rigs. Let me emphasize the plus rigs. It'll probably be more. We'll come out with the final number in the February call and also the annual budget for 2014.

Slide number 5, again, in our joint venture area with Sinochem, we brought on a 12 well, successful wells in the Giddings area. IP rate of over 1,000 barrels a day equivalent. This is where the B is about 500 to 600 feet thick. We staggered them, 12 Upper and Lower B wells. We also tested 77-acre spacing. Tim will talk about future downspacing going to 50 acres in 2014.

Eagle Ford had a very successful quarter even though we had a delay due to pad drilling in regard to the production. It's picking up significantly going into the fourth quarter. We've added 300 locations do to downspacing, going from 120s to 60s, with a 20% increase in average EURs. In addition, Tim will talk more about going down to 40-acre spacing, as we're testing now.

We also had an interesting well in the Upper Eagle Ford Shale, with an IP rate over 1,600 barrels a day equivalent. This will add substantial amount of incremental locations as we develop the Eagle Ford, primarily in Karnes and DeWitt in that area. We also, as we have discussed over time with some of you all, we announced the agreement to sell Alaska assets for $550 million to Caelus. Expect to close by year end or early 2014. That capital will go back into developing the Wolfcamp and Spraberry out in west Texas, primarily in the north. Net to book went down from 22% to 21% in the third quarter.

Going to slide number 6. Really the most important point here is that we under spent during the year, cash flow. The key point here is that cash balance actually built up from about $700 million last quarter up to $744 million the end of third quarter. Again, with the cash coming in from the Alaska sale of $550 million, it'll put us over $1 billion primarily. That's why we're looking at adding potentially more rigs than 10 going into the north.

Slide number 7, annual production growth. We've tightened our guidance down to 172 to 173 with 14% production growth. As you can see, with this slide and also the next slide, our lower end of the range for fourth quarter, 179,000, we're already there today at 179,000. The range is 179 to 184. Again, the increase in pops is important that we're adding over twice as many pops, wells being put on production in both Eagle Ford and the Spraberry/Wolfcamp interval, fourth quarter as compared to the third quarter.

We're also had a pick up in liquids. We're already up to 64%, on our way towards 70% later in the year. As expected, the focus going into next year is going to be less science, more development drilling primarily in the Wolfcamp zones. I think you will see us come out with a much higher growth rate than we did with the 14% this year. Again, due to pad drilling and due to the science in west Texas, we will be focused on moving toward the higher end of the number, of the 13% to 18%, as we move into future years.

Going to slide number 8, just a general breakdown of how we got to the quarter production and, again, focusing on fourth quarter. As you can see, we averaged 93 wells put on production in Spraberry/Wolfcamp and Eagle Ford the first half of the year, 46 third quarter. We are going to 90 for the fourth quarter. That's why we are seeing already a big uptick in production at 179,000, in the range of 179 to 184. This does take out Alaska as discontinued operations.

Going to some of our tight curves on slide number 9. As you can see, we're very excited about the Wolfcamp D Shale wells. The first well, with over 60 days of production, you can see is exhibiting close to an 800,000 barrel tight curve. Based on the results I've seen out in Glasscock County and Reagan County, this could be the best well to date except for the fact that we just brought a well that's at 9,100-foot lateral, Wolfcamp D well that came on over 3,100 barrels a day. Obviously, we are excited about that well.

It looks like Midland County could be a great county, and maybe going into Glasscock County for the Wolfcamp D. Our Martin County well, in the Scharbauer, looks like it's going to exhibit something above a 500,000 barrel tight curve. These wells do start off a little bit higher ratio gas-oil ratio in the 1,500 to 2,000 versus the Wolfcamp As and Bs at around 1,000 gas-oil ratio.

Looking to the map on slide number 10. You can see we did step out 50 miles. We essentially took the better wells of Apache and Laredo out to the east in Glasscock County and also in Reagan County as compared -- but stepping out, it shows how prolific and the potential of the Wolfcamp D. We are excited about the future development in addition to the Wolfcamp A and B wells.

Slid number 11, an update on the curves of the Wolfcamp A and B wells. I think the note, we've added two new wells, the well in black, which is another Hutt well with the highest IP of the Wolfcamp B. In addition to the Scharbauer well, which is only about five miles away from the Mabee well, we cannot fully explain the reason for more water production. Obviously, we could not get a high peak rate, but it's already in line with the 800,000 barrel tight curve or higher. As you can see, the green curve, essentially flat production over the last 40 days.

Going to slide number 12 in returns, just to update everybody on these returns. This is strictly the northern horizontal Wolfcamp program, ranging in tight curves between 650,000 barrels to 1 million barrels. Returns go from 60% up to 125% up to 150%. The 800,000 and the 1 million, obviously, are paying out less in one year. This is based on $95 oil flat, $4 gas flat and a 7,000 lateral with a well cost of $8 million.

Even though down south, with JV with Sinochem, we're getting our wells down to $7 million already, we're assuming they're going to be a little bit more in this deeper area at about $7.5 million. Then, we got room for any wells such as the Wolfcamp D, which will cost us about $300,000 more to drill those wells. It will be covered by $8 million well cost. This is with no science, obviously, with $8 million, it's pretty much into the pad drilling mode. So, again, great returns.

In summary, on slide 13, again, another great quarter for us. Proving up the Wolfcamp D, I think, has been the big highlight - Announcing that the largest Wolfcamp Shale B well interval with the Midland Basin. The downspacing and bringing on our 12-well downspacing pilot. The downspacing to 60 acres in the JV area. Again, continued downspacing in the Eagle Ford, with a very successful Upper Eagle Ford Shale well. Then, the announcement of our Alaska subsidiary. Really summarizes a tremendous accomplishment during the quarter.

Let me turn it over to Tim to give you more details.

Thanks, Scott. We have in fact had some very significant accomplishments in the third quarter. I plan on getting into a little more granularity on the go-forward plan.

I will start on slide 14, that's just covering the Northern Spraberry/Wolfcamp acreage drilling plan. It's shown here, it looks like we'll spud a total of about 34 wells this year, split with about 19 of those wells with the various Wolfcamp Shale intervals and about 15 wells within the Spraberry and Jo Mill intervals.

As you know, we've increased to five rigs in the north, really near the end of the second quarter. We'll be at 10 plus in early 2014, as Scott mentioned. Really, we're well on the way to executing the drilling plan in the north for the remainder of the year and into 2014.

Going, then, to slide 15. This is, again, regarding the activity in the north. This graph, this slide will cover all the status of the wells that are either drilling, awaiting completion or flowing back. Actually, in the text, all that information is enumerated. I would add one thing to that. That is, we have a couple of important wells coming on here, actually, in the next couple days.

Where we had drilled the first O'Daniel D well that Scott mentioned, it was such a phenomenal well, we'll be flowing back our first B well in that area this week. In addition to which, we'll be flowing back a Lower Spraberry Shale well in Andrews. These wells, in terms of performance, are coming at us. We'll be able to talk more about them after the fullness of time.

I would like you to focus on the map on slide 15 because what it shows is the activity, both with regard to producing wells, where wells are being completed, and where they're being drilled. The main message there is that our drilling activity is now being disbursed across the leasehold. For example, we're showing that we'll be drilling our first well in Glasscock County here in the fourth quarter.

You can see, we're not just concentrating on so called sweet spots. We are spreading around the campaign, around the acres to be able to learn what we can and learn the aerial extent of all these intervals.

Importantly, we are moving further towards pad drilling. In fact, the majority of these wells will be drilled on two-well pads. Of course, that has the affect of increasing the spud-to-pop times, as you have to drill the wells and complete both wells before you can put them on production. You can be out at, let's say 150 days, which leads to the production lumpiness that we actually saw in relation to Eagle Ford in the third quarter.

We will have the 10 plus rigs running by early 2014. When you factor in 150 or so days of waiting, by the time we get some of these rigs up and running in the early part of 2014, they will have essentially no production impact til the second half of the year. That has to be worked through in terms of a back-weighted production growth forecast in 2014. Suffice it to say, the northern program is on schedule and progressing very nicely.

Let me turn to 16 now, and to our activity in the JV area in the south. We did put 16 new Wolfcamp wells on production during the quarter. The wells came on basically as expected. It depends, of course, on where you drill the wells in the acreage, but our averages are essentially on target.

We are currently running eight rigs in the south drilling about 100 wells this year. Half of those are focused in the northern area of the southern acreage where we believe the returns are higher. We continue to be doing testing regarding slickwater and hybrid fracs as to which direction we'll go for 2014 campaign. Because of the cost of hybrid fracs coming down, the gel costs having been reduced, we see them today having similar costs. Of course, the hybrid fracs use less water, so that gives them somewhat of an advantage. We'll be making a decision how to proceed with the campaign here shortly for 2014 in terms of how the wells completion will be conveyed.

We are now heading much towards a campaign with longer laterals. In fact, we've drilled nine 10,000-foot laterals year to date in the south. We continue to see really phenomenal improvement by virtue of increasing the lengths from say 7,000 to 10,000, where we see a 30% or 40% bump in production at about 20% cost increase. That trend will continuing going into 2014. In fact, our average lateral length as currently calculated for 2014 is estimated to be somewhere between 9,300 and 9,400 feet for the whole campaign next year. 100% of those wells will be drilled on pads in 2014. As a result of that, we're going to have the same effect we've been mentioning earlier regarding the fact that as we ram up the rigs, we'll some lumpiness in production just as we have described in other areas.

Let me turn now to slide 17. Just beginning to see the production data for our first Wolfcamp downspacing test that Scott referred to. This is really important for us to understand, in terms of our go-forward plan, in terms of what ultimate spacing makes sense in the field.

This slide 17 has a lot of information on it. I'll just begin by pointing out where we are. We here in the Giddings area. Of course, we drilled some very good Jo Mill wells, very good Wolfcamp wells in the Giddings area. So, we've come back here with the campaign of having drilled 12 wells on three-well pads, so 4 pads, 3 wells each. You can see them depicted in the map at the bottom left. These are 6,200 feet laterals. That is because we're relatively limited on our lease line configuration in this area.

The easiest way to describe it is to look to the bottom right of the graph where it actually looking down the horizontals. We call it a gun barrel view. You can see what we are doing in terms of altering the spacing on staggered laterals. The 116-acre spacing, that would be more of the traditional way, the red dots at about 720 feet spaced. Now, we're looking at downspacing this most recent campaign to 480 feet or about 77-acre spacing. So far the results look very encouraging. It will take more time, of course, before we can make any specific statements about whether this is the optimal spacing.

With that said, we are planning, in the early or mid-part of next year, a further downspacing to about 310 feet, which would be about 50-acre spacing. We are on to the notion that we have got to understand this before we set a go-forward plan. It's a really exciting pilot project. The objective which is to know where we go with spacing in 2015 in the forward plan. What really is critical about this, the information that we're gathering here, we believe the results of that information will be transferable to the northern acreage. So, this is something that is very important to watch in terms of the future of the drilling campaigns.

In terms of slide 18, as a result of all of the activity I have been mentioning, production from the horizontal wells in this field is starting to ramp up considerably. In fact, you can see that on the graph, where we've shown the horizontal contributions in the lighter green color. Our production was flat in the third quarter it turns out. That's simply because of the same thing I mentioned earlier, which is we weren't even running our five rigs until very late in the second quarter. The main effects of that we'll be seeing in the fourth quarter and in the first quarter of 2014.

That said, we are increasing our guidance. We expect the fourth quarter to be very strong as we place many of those wells that have been drilled throughout this year on production, about 45 different wells. We anticipate the fourth quarter, as shown, to not only be very strong but to lead to an increase in our guidance range for the year to about 80,000 to 81,000 BOE per day.

Basically what it amounts to is the horizontal campaign is offsetting some vertical decline. With running 15-vertical rigs, as we currently are, we are doing so in order to meet continuous drilling obligations on certain big ranches in the area, and as we go forward, those 15 rigs running will essentially allow a situation where vertical production decline rate ends up being about 10%. As we ramp up horizontal drilling, especially with high-rate wells, we'll see the horizontal rig count have the effect of being able to significantly offset these vertical declines and therefore lead to overall production in the field. Needless to say, we're very excited how our Spraberry and Wolfcamp drilling campaign is unfolding and there is lots to come.

On 19, turning to the Eagle Ford. For the first time we'll be talking here about the results from downspacing in Eagle Ford. It looks very encouraging so far. For some time now we've been downspacing wells from what would in effect be 120-acre spacing, say a 1,000 feet apart to now 500 feet or about 60-acre spacing. That is shown on the map, the areas we are doing that, three specific areas.

Having done this work, we believe we already can say we will be able to add 300 locations in our liquid-rich areas due to the downspacing. We've tested quite a large number of wells on three- and four-well pads, over 50 wells. As Scott has already alluded to, the zipper frac technology has really allowed us to really feel comfortable in saying these wells that have been zipper fraced exhibit probably 20% more EUR potential than those that are single-well drilled. Really what it amounts to is you're getting much more effective stimulation of the rock in this area by virtue of doing zipper fracs that are relatively close to each other. It just provides a better fracture network.

As I turn to slide 20, this gives you a depiction in the similar vein than we did with the Giddings area. Looking down the well bores at the configuration, this configuration as to the vertical spacing and the horizontal spacing differs depending by where you are in the field. Because as you recall, across the Eagle Ford Shale, we have different areas where we have dry gas all the way to liquid-rich oil. The spacing depends where you are.

Now, we are in the process of actually going down to 300-feet well spacing. That would be about 30 to 40 acres, and we're testing that in those same areas where the 500-foot well spacing, we believe, was successful. You can see it here in 3D, kind of how the staggers look. As you take a look at the gun barrel views, what you'll notice is we have drilled our first Upper Eagle Ford wells, the one specific well that Scott mentioned is in Karnes County. It had a very strong 24-hour IP rate of over 1,600 BOE per day.

That well, as has been the case in all of our Eagle Ford wells, has been choked back. It's only producing today on 8/64 choke, so it had potential, obviously, to do significantly better than that. We choked back these wells for longer-term benefits related to their ultimate resources or reserves.

Basically what we are seeing in this well, though, is that the staggered wells, the wells in the Upper Eagle Ford, so far, exhibit very similar rates as the Lower Eagle Ford. That gives us a lot of confidence moving forward. Probably about 25% of our acreage is perspective for the upper intervals. The combination of downspacing and the potential for the Upper Eagle Ford Shale zone are adding to our drilling inventory, specifically in the liquid rich area.

Finally, on slide 21, we're talking here in this slide about the Eagle Ford production growth rate. Of course, we were down in the third quarter as reported. What happened, of course, is has already been mentioned by Scott. We went to a higher percentage of pad drilling during the third quarter and actually went to where we are drilling more wells per pad on average, and of course that saves us a substantial amount of money. It's definitely the right long-term decision in terms of costs and capital efficiency, however it has the effect of pushing back production when you increase pad drilling or when you increase the number of wells per pad.

The other factor that comes into place, as we get into more pad drilling and zipper fracing is, where we have wells in the area that have to be shut in while we're fracing the related wells, especially the downspaced wells. At certain times during the third quarter, we had as much as 8% of our production, our total production in the field, shut in while we were fracing offset wells in the downspacing test. When you're shutting in 8% of your production voluntarily, you can see the result that we got, being somewhat expected. However, as we get into the fourth quarter we'll be increasing our pop rate, Scott already mentioned that, to about 45 wells. I do expect Eagle Ford to get back on its growth trajectory in the fourth quarter.

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

Thanks, Tim. I'm going to start on slide 22., where we had net income attributable to common stockholders of $91 million or $0.65 per diluted share. That did include unrealized mark-to-market derivative losses of $85 million or $0.60 per diluted share. Then, we had aggregate unusual items totaling $0.01. Adjusted for those two items, we are at $176 million or $1.26 per diluted share.

Looking at the middle of the page, where we show results relative to our third-quarter guidance, Scott and Tim both talked about daily production, so I will pass over that. The other items were all within guidance other than for G&A. It was higher primarily due to increases in stock-based compensation expense as a result of the Company's stock price performance. When you look at current income taxes, we did benefit during the quarter from capitalizing IDC more than we originally planned, which had the effect of reducing previously recorded AMT and Texas margin-tax estimates.

Turning to slide 23,where we look at price realizations. You can see from the green bar that oil was up 12% to $101.83 as compared to the second quarter. Similarly, NGL prices were up 7% over the quarter and gas prices were down 11%, as we have seen storage and supply continue to grow. Looking at the bottom of the slide, you can see under the columns, the impact of the derivative portfolio. As noted at the bottom of the slide, we also record that in net derivative gains and losses on the income statement.

Turning to slide 24, production costs. I think the message here is that if you look across the last five quarters, it's been fairly consistent, our total production costs for BOE, specifically when you look at the third-quarter and third-party transportation costs. Those were higher during the quarter due to some one-time charges associated with transportation in the Eagle Ford Shale area. Then, if you look at base LOE, we were up slightly for the quarter, primarily due to higher salt water disposal costs and some labor cost increases.

Turning to slide 25, you can see the Company has a very strong financial position with no near-term maturities on any of its debt. We have significant liquidity with cash on hand of $744 million and an undrawn $1.5 billion credit facility. So, excellent financial condition at the end of the third quarter.

Turning to slide 26, fourth-quarter guidance. It is important to note that this does exclude Alaska, which we expect to be in discontinued operations for the fourth quarter. Daily production, as Scott mentioned, of 179,000 to 184,000 BOEs per day. That does reflect the higher number of wells we expect to be placed on production during the quarter associated with pad drilling. The rest of the items on this page are consistent or similar to past quarters, so I'm not going to go through those individually, but they're there for your review.

At this point, I think we'll go ahead and open up the call for questions.

(Operator Instructions)

Charles Meade, Johnson Rice.

If I could try one on the Wolfcamp D just to start out with. Obviously, that O'Daniel well is a fabulous rate. But looking at all three of them together, it strikes me that there is a wider dispersion of your results in that zone between the best and the third well than we have seen in other zones.

I'm curious, has that been a point of discussion for you guys internally? If there is, are there any mitigating factors that you can share about what made one of those wells twice as good as the other?

Charles, there's not too much difference between the Hutt D well and the O'Daniel well. The Hutt D well is a shorter lateral, so you need to move it up about 30% on that rate. There is probably 200, 300 barrels a day difference between the two wells. It's not as big as you think. It's probably less than 10%. To me, if the Hutt well would have been out 9,100 feet it would have been up in the high 2,000s BOE.

It points toward -- the Midland County area has always been the best county for vertical drilling. It just shows, again, that the Midland County wells, I think, are going to be the strongest wells. There are some from other operators in Glasscock, it's a couple from Laredo over there, but we're still very excited about Midland County. It's a little bit deeper.

The well in Martin County is a pretty good step out, so we need to drill some more wells south of the Scharbauer to see and get more wells to see if, as you go north are you going to make a 500,000 barrel type curve? A lot of the wells that, and look at other investor presentations of other operators, they're saying the Wolfcamp D of decline is going to do something around the 500,000 to 600,000 range. We have got two good wells. If you normalize them, they're going to be very close to each other. We still think we have a big area, probably in southern Martin, maybe all of Midland and some of Glasscock.

Got it, Scott. That's great, too, that's what I was looking for is, that maybe that Scharbauer well, as you call it, might be different type curve than what you're going to see in Midland, for the D.

Exactly.

Got it. Then, the second question, the other -- I know you guys have mentioned that with all the fabulous things that are going on in the Midland Basin for you, a lot of times the Eagle Ford gets overlooked. I thought one of the really positive things here was this 20% EUR uplift with the zipper fracs you're doing over there.

I'm just curious, are you also trying the zipper fracs down on this downspacing pilot in the JV area of the Wolfcamp? If you are, is that a possibility that we should look out for, that you might have a similar EUR uplift in the Midland Basin with that completion design?

Charles, this is Tim. I think it's pretty clear from our data, since we've done the zipper fracking in so many Eagle Ford wells that we have been able to establish this 20% uplift. I think as I mentioned when I was covering those slides, it has to do with, we think, improved fracture network.

Basically what it amounts to, if you take a look at the microseismic on this, and these wells are relatively close together, you're really pulverizing a huge amount of rock in and around the well bores. There's a lot of connectivity as a result. That, if you take a look at the technical data we look at, it's pretty clear for you to have a much higher density of events occurring around the well bores when you're doing zipper fracs and relatively downspaced wells.

The truth is, as we get into further downspacing efforts in the Wolfcamp, which we just started of course, it could easily be the case that we see that. It's too early to know. You would expect it, just based on the fact that you would hopefully be improving the fracture network as well in the Wolfcamp, but we'll know more about that after a few more quarters.

To hit one quick detail, are you doing it on your downspacing pilot in the JV area right now?

Precisely, all those wells are zipper fraced.

Got it. Thank you very much, gentlemen.

Doug Leggate, Bank of America, Merrill Lynch.

I've got a couple, also, if I may? Scott, it seems you've worded your press release fairly carefully by saying that the initial wells drilled in the Wolfcamp A and B should have EURs, you think, north of 800,000. But, they are pretty well spread out. One of my questions is, what can you say at this point about the repeatability across your acreage? I have a follow up, please.

Yes, I think, as I said, I think that the general area of 800,000 plus was going to go from the Giddings area, in that general area in northern Upton County up throughout Midland County and up to the, maybe, up in Martin County. We do not yet have any wells over in Glasscock County, but obviously it's a great area, our driver unit and some other acreage.

We are going to be drilling some in Glasscock County. The O'Daniel well, as Tim mentioned, is going to be coming on, the Wolfcamp B, here shortly. We'll have a marker there. It's right in the center of the entire area. We think it will eventually apply to 800,000 plus, will apply to that general area.

Your production guidance, Scott, is still, if I'm not mistaken, assuming 500,000 barrels the 13% to 18%. Obviously, the implications are the numbers goes higher. What can you tell us at this point as to how you think about the development plan and ultimately the growth targets?

As I stated, and when I mentioned the 10 plus rigs, look at the plus side, we're going to come out with more rigs than 10, obviously, with our cash on the balance sheet. It looks like we will have the strip at $94, $95. We're pretty much essentially hedged at $94, with a downside of $94 next year with 85% of our crude. We're looking at running more than 10 rigs. I mentioned also, 2014 was supposed to be another year of science.

Having these type strong wells, in the A and the B and the D, we will probably end up being focusing more on A, B and D wells even though we don't have results from the Spraberry. I think the Spraberry wells will be good wells, but it's going to be hard to compete with wells that are paying out in less than a year, 125% to 150% return. We're going to focus a lot more of the rigs up in the north on the A and the Bs and the Ds and drilling pad drilling. When we come out in February, we'll come out with our CapEx and our long-term, three-year production growth rate in 2014 through 2016.

Okay. Forgive me for laboring this point a wee bit, Scott, but these are obviously very strong-well results you have reported, but it doesn't seem to be translating yet to the production performance. Is that just a function of, as you say the science or the spottiness of where you're bringing these things on? How would you account for that? When would you expect it to become ratable?

Remember, we were just running one rig in the horizontal Wolfcamp in the north, early part of the year. We moved to five. We're just now moving to eight. We're going to be starting the year with 10. It will probably higher than that.

So, you have the ramp up in the north with the rigs. Then, you have science on essentially every well we are drilling in 2013 in the north. That's the big item. We pretty much have a very good picture of what is happening in Eagle Ford going to next year and we have a very good picture of what is happening in the joint venture area with Sinochem, so the north is our big swing factor. That's where the focus is going to be on more pad drilling, more development drilling, and stretching out the science through 2015 or even 2016 in some of these zones.

Can you give us stop as to where the growth rate goes, Scott? I will lead it there.

I alluded to the higher end of our 13% to 18%.

All right, I'll leave it there. Thanks.

Dave Kistler, Simmons & Company.

Thinking big picture, when you guys talk about the resource potential of 4.6 billion barrels across your acreage, can you quantify how many intervals you are including in that? What kind of spacing you are including in that?

Yes, it's the same number we're giving out for the 50-billion barrel resource potential for the entire Midland Basin in the Spraberry/Wolfcamp zones. If you remember, we're only adding four zones. We're using a very conservative, ultimate. It's on 140-acre spacing.

Tim is already talking about, with him and Bill going down to 77-acre spacing. They'll be testing 40-acre spacing. You could easily double or triple the resource potential by just downspacing. That doesn't include adding more zones for these other two Spraberry zones, which we didn't include. Our numbers are going to go up significantly along with the 50-billion barrel number, it's going to go up significantly over time.

Great. I appreciate that color. Thinking about the rate cadence you were talking about in the northern Midland Basin, the 10 plus rigs, can you talk about what that might mean to your vertical integration efforts? Do you look at increasing your frac crews, anything like that?

Dave, this is Tim. Just to let you know, we do have two external frac crews working only on our vertical wells today. All the horizontal campaign is being pumped by Pioneer Pumping Services. That said, as we go forward into 2014 with a bigger rig count, we'll probably be bringing in some third-party resources.

That's basically just where the market is today. The margins are relatively low, which means third-party rigs, third-party fleets are very competitive. As a result -- we really never wanted to be 100% vertically integrated anyway. It was a process of dropping the vertical rig count. We will have a lot of comfort in bringing on some third parties to pump the incremental wells.

Okay, I appreciate that. One follow up on that, when you think about the savings generated from your vertical integration efforts, what do you estimate right now, that savings as on a per-well basis?

I just look at this way, the margins right now, if you look at pumping services, are generally speaking going to be 10% to 15%. That's just where the market has landed in the downturn and the over building of pressure pumping. That means on a several million dollar completion, we're dealing with several hundred thousand dollars, and we can save just with a 10% or 15% margin.

Okay. That's helpful. I would guess it would have to be significantly higher for you guys to then look at adding additional capacity?

We've got good places to put capital. It's called drilling horizontal wells in the Wolfcamp and Spraberry. That's where we land that decision versus spending capital on pumping services with margins where they are today.

That makes good sense. Appreciate it, guys.

John Freeman, Raymond James.

You mentioned that of the 15 vertical rigs that you are running in the Spraberry field that you'll likely start to reduce that going forward and shifting more to horizontal drilling. I want to make sure that I'm understanding correctly what your flexibility is there? My understanding is that that continuous drilling obligation requires about 250 wells a year, so you basically satisfy that with 13 vertical rigs.

Initially, you can drop a couple of rigs from the 15 to 13. Then, maybe, if I'm thinking about it right, a couple years down the road maybe you start to replace some of those remaining 13 vertical with some horizontals to satisfy some of the obligation? Am I thinking about that right?

You are on the mark. You're pretty close. The scenario we're looking at right now is probably more in the neighborhood of 12 vertical rigs next year from our beginning point of 15, for the reasons you mentioned. The real question is what is the exact number of horizontal rigs we use in the north? Because it's also the case as we build the horizontal-rig count, we can also then supplant some of the needs for vertical drilling and use the horizontal wells to meet our needs on continuous development. If you look at the next few years, there is a plausible scenario where we actually have zero vertical rigs running within the next few years.

Okay, great. Then the last question for me is more focused on basically the spud-to-POP time. On the northern acreage where you say it's basically 120 to 150 days, and that includes some extra time related to science, the first part of it would be how much time is related to the science?

Then in the south, the 150 days, where do you think that could go to over the next couple of years? I'll stop there. Thanks.

I think if you take a look at it, if we are dealing with 150 days in the north, that is related to probably roughly 30 days plus related to science. When you look at our southern target for 2014, it's more of like 120 days, 115, 120 days. That's where I account for the science. In the south, we're basically not doing science any more, is what it amounts to. It was about 30 days plus worth of science time.

Great. Thanks, guys.

Brian Singer, Goldman Sachs.

I wanted to follow up on a comment you made with regards to the development plan earlier. I think you talked in the past about potentially developing together the Wolfcamp A, B and C, and hopefully the Spraberry Shale. It sounds like that has shifted slightly to the Wolfcamp A, B and the Wolfcamp D. I want to just get a sense as to whether that is based on the outperformance of the Wolfcamp D? Whether it's based on expectations for a less attractive economics relative to the three zones at the Spraberry? Or, you're just waiting for more details? Could you develop four zones simultaneously, would be a follow up on that?

It's strictly the outperformance of the A well and also the D wells. We knew the B was going to be good, but the outperformance of the A well and the D wells, the focus will be on the A, B and D. It has nothing to do, we have no results except the Giddings results on the Jo Mill, still, on the south and we have the rising Star well, lower Spraberry Shale well.

We just recently picked up the data from the Middle Spraberry Shale well, by Rising Star. Essentially, we have little to no data on the Spraberry. We do know that the Spraberry is lower pressure. There is lots of oil there. It will probably produce. We have to get our well costs down and we need more history.

It's going to be hard to beat wells paying out less than a year, so it's the focus on the A, B and the D is what we will focus most of the activity. We're increasing the number of A, B and D wells next year versus our previous our plan going into 2014. That'll be less wells in the Spraberry Shale. The Spraberry Shale wells and the Jo Mill turns out they're great wells, we can always increase the activity back into 2015 and 2016.

Great, thanks. Then as a follow up, as you talk about raising your oil cuts over time to 70% and ramping up activity in a more concentrated manner over time, how should we expect the operating costs trajectory? On one hand, does it go up, because it's oilier, on the other hand because you've got some scale should we expected relative to say fourth-quarter levels here at production cost to fall?

In a long-term model over the next five years, we see a couple dollar drop. If prices, inflation is minimal, commodity prices stay flat, we see about a $2 drop because we're bringing on all these bigger potential wells. They do reduce operating -- they average with your higher operating costs, the vertical wells, and they ultimately do lower operating costs on our per-BOE basis.

Do you expect any of that next year? Or just because it's a science year, that's really more longer term?

Dollars over about a five-year period, so you pick up a little bit each year.

Great, thank you.

Leo Mariani, RBC Capital Markets.

Obviously, very prolific wells you announced today here. Looks like you guys maybe are using a little bit longer laterals, little bit bigger fracs on these wells. I know you talked about costs for 7,000-foot lateral. As we get into drilling next year, do you think the lateral length in the north is likely to be longer than that? Can you maybe ballpark costs, if you are, in fact, going to longer laterals and bigger fracs?

If you take a look at it, Leo, I think it will be the natural tendency where we can to increase lateral length. That said, of course, lease limitations, or lease line limitations will be the governing factor. The answer is yes, we'll be looking where we can drill longer laterals. If you look at the costs, though, in the north we are deeper, of course, and so we show a cost roughly $7.5 million to $8.5 million. That is for 7,000-foot laterals and of course it has to with incremental depth.

I think you add a few hundred thousand when you get out to about 10,000 feet, maybe $400,000 or $500,000. You will incrementally be adding costs, typically about 20% additional costs, so several hundred -- $200,000, $300,000, $400,000.

That said, what we're also saying is we still see a pretty strong linear relationship between the extension of the lateral length to the incremental production rates and EURs from the wells. In fact, the incremental production rates, if they're linear with the lateral going from 7,000 to 10,000, it's some 40% increase. That 20% increase in cost becomes relatively insignificant considering the amount of incremental production.

That is helpful. In terms of some of these wells you announced. You, obviously, gave some 24-hour rates and then some 30-day rates, as well. Just looking at some of the 30-day rates that you gave with the package of well results, it looks like some of those were down 50% versus 24-hour rates.

Any color you guys have, potentially, on the declines? Is that following your type curve at this point? With some of the bigger fracs you put on it, do you think it's giving you higher IP? Just any thoughts on what that could lead to in terms of longer term EURs here?

I think a rule of thumb is the more sand you put in the bigger the frac. The longer lateral length is going to be a plus for any well. That is what it's showing in the JV area with Sinochem with all the long laterals. So far, the only long lateral we have up to the north is the Wolfcamp D well.

We will have several more eventually to compare it. Obviously it's working with that well. We don't have enough data to the north yet. The rule of thumb, it should work just like it has to the south and just as it has in Eagle Ford. The longer laterals, the more sand you put in, the increase in production and increase in reserves follows.

Okay. So, just on the 800,000 BOE type curve, just to be clear, so that's on the 7,000-foot laterals you are talking about, right?

Exactly.

Okay.

We will see a proportionate increase as we start increasing our laterals in the north with a corresponding increase in well costs, but you still get a big pick up in regard to less well cost increase versus the increase in production and an increase in reserves.

That's helpful. In terms of the Upper Eagle Ford, somebody went well on production at this point in time. Are there lower Eagle Ford wells directly offsetting that particular well on tight spacing? If so, any thoughts on communication? I know it's early.

We do have offsetting Lower Eagle Ford wells in the area. I think it's the case, in fact, there's five lower offset Eagle Ford wells in the area. As a result, I think we could look at this and say it's pretty definitive we're getting a very strong well here, as it's comparing equally with what you would expect from the Lower Eagle Ford well.

So far, really no communication. That is a positive right now. It means we possibly can go to this lower downspacing to the 300 feet. It has a good chance of being successful and add more locations.

Okay. That's helpful. I guess on the southern JV acreage. Obviously, you've got stacked wells in the B zone, Upper and Lower. Longer term, do you think there maybe communication there? Are you seeing any evidence at this point?

Too early to say. Those wells were just put on production hear a couple two, three weeks ago. We're not going to be able to outline the net effects of the downspacing in a very granular fashion probably til the end of the first quarter. It's going to take that long before we see well results and see decline curves to know the answer to your question.

The hope is that you see something along the lines of what you see in Eagle Ford by the downspacing, and that is a more dense fracture network that comes out of the fact the wells are closer drilled, closer together and the zipper fracs have the effect of really pulverizing a big volume of rock. That's the hope, but it's too early in that case as compared to where we are in Eagle Ford.

Okay. Thanks a lot. Appreciate it.

Matt Portillo, TPH.

I was just wondering if you could provide an update on your expectations for well costs on the 10,000-foot laterals in the southern part of the play? Then, as you mentioned early indications, or as you've built more data on the production on the southern wells, any indication on how EURs are trending in the southern part of the play?

First of all, on the well costs, I think of it more in terms of the overall program. I mentioned earlier that the program's going to average say 9,300 to 9,400-foot laterals. That's basically $8.5 million in our plan. You could ratchet that up if it's actually a 10,000-foot lateral. That's the way I'd be planning it.

Okay. In regards to corresponding EURs, how are you thinking about the EURs on those wells?

The EURs, if you remember in the south, we have an average of 575,000 BOE. That ranges, of course, depending upon where you are in the south. To the extent the Giddings area, it's substantially higher than that, 650,000 or more. As you get into the southern areas, we see EURs perhaps getting down to 450,000 or 400,000. The average of 575,000 is still holding up. That's based on a 7,000-foot lateral. To the extent we actually can extend these laterals out, as we've been talking about, we will probably be bumping that. We need to drill some more wells before we're able to establish that.

Great. Then just one quick question on the Eagle Ford. As you guys continue to extend the inventory life on the play, I know you mentioned potential acceleration in the northern Wolfcamp. How does the Eagle Ford fit into your accelerated drilling program with increased inventory? Is this something that you may look at in 2014?

I think, obviously, we're probably going to be maintaining roughly the same rig count over the next few years, at the current levels. We do have to get approval from our partner, Reliance, but we're looking at maintaining the same rig count. We're confident that we can continue to grow it over the next three to five years.

Great. Thank you very much.

Brian Corales, Howard Weil.

Most of my questions have been asked and answered. The Upper Eagle Ford, do you think it's a separate reservoir or is this another form of downspacing? Also, are you all getting any contribution from the Austin Chalk that you know of?

If you take a look at the information we showed you, and especially the gun barrel view graph that's actually on slide 20, you can see that in some of the areas you're actually drawing the Upper Eagle Ford 100 feet above the Lower Eagle Ford well. So, you could make the case that that would be tapping into and completely fulfilling the need to complete the whole, say, 300 feet of the Eagle Ford. However, as you get up higher in the section, I think it's definitely the case that we will see some contribution from the Austin Chalk.

Okay. On the Midland, are you all planning a pad maybe to test multiple zones with tight spacing, something -- I say pad but maybe drilling on one section, where you could potentially have 30-plus wells into one section to see the viability and potential communication?

I think the answer to that question is that is going to be something that is a future project. However, it's the case that we need to get all these wells drilled in 2014 to know what that would look like. In other words, it's along the lines of what Scott said. Would it be an A, B, D combo set of drilling? Would it include a Spraberry zone? A Jo Mill zone? Just a Lower Spraberry zone? That's what we are doing, in the case of our drilling campaign, is understanding what that would look like. I think that is a 2015 project.

Okay. Helpful. Thanks, guys.

Gil Yang, DISCERN.

The O'Daniel well was really pretty spectacular. Maybe can you comment -- I know you don't have a 30-day rate out, but can you comment on, off of that IP, is it tracking with the other wells we're doing?

Yes, it's still making over 2,000 barrels a day after about five days. You can plot it yourself. It's still outperforming all the Cline wells, the D wells, and really over the B wells, also.

Okay. Obviously, you seem pretty excited about that result and so you are drilling the B well right next door. Is that enthusiasm an indication of a specific issue in that area? Or, do the D wells in general give you confidence that the east-west extent of the A/B zones are also going to be similarly strong?

Gil, this is Tim. I think we feel like the A, B and D are laterally extensive, and basically this is across the whole northern acreage without a doubt. The O'Daniel B well, just so you know is just being put on production. Right now, the D well was put on production, whatever Scott said, five days ago. These are wells were drilled back to back, so it had nothing to do with D results, just O'Daniel's B was drilled where it was.

Was there any reason why you chose the O'Daniel spots to drill those wells?

Two simple reasons. One, it's 100% working interest.

Okay.

It's right in the center of the area we have been drilling between the Glasscock play and also the Hutt area. To prove up the center part of the acreage.

One additional little factoid is it's 15% royalties, which is a positive.

That's nice. Great. Thank you very much.

Will Green, Stephens.

I wonder if you guys could speak to the oil content on this recent batch of wells? I know you mentioned that it's in a more mature area that lead to the higher gas content. Now, that you guys have a ton of production history on the first wells and then more recently have drilled in some of these more mature areas, can you guys comment on hydrocarbon split for the EURs on the A, B and D, if you have enough info on the D so far?

The only difference is the D wells, I'm excluding the D well up in Martin County. We only have one result up there. It was 60% oil. The other two wells in Midland County were 69% oil. They're coming on about 1,500 to 2,000 gas-oil ratio. Where the Wolfcamp A and B are coming on around 1,000. It is a little bit higher in gas-oil ratio. It is about a 1,000 feet deeper, a little bit more mature probably. It's a little bit more gas, but it's insignificant when you look at the economics. The difference of 69% and 74%.

Sure. The rates looked great inside. I don't want to discount that, but on the EUR expectation you think that that holds pretty steady? Do you think we settle out in the 60% to 70% range? I know you had a great slide that broke out your early wells tracking low 70% in terms of oil cut for the EUR. Is that a good expectation?

We need more history on the D. I don't remember what the wells off in Glasscock County are doing, what they are holding. We will have to research that, of other operators. We just need more history to determine that. The gas-oil ratio, in general in most of these zones, will tend to increase a little bit with time.

Great. I appreciate it, guys.

Michael Hall, Heikkinen Energy Advisors.

A lot of mine have been asked and answered. One thing I just wanted to clarify and see if I'm thinking about it right, as it relates to the whole lumpiness and results flowing through, wells flowing through to the quarterly results. Sounds like we probably continue to have the effects of this lumpiness through at least the first half of next year. But perhaps as you get to scale of the program fully ramped up we'll see some smoothing out of that lumpiness in the second half of 2014 and early into 2015. Am I thinking about that correctly?

It's a combination of factors, Michael. One is, we are still increasing the rig count. That'll happen between now and the end of the year and into next year. Every day you bring on a rig to start doing pad drilling, you now can set the clock for, depending on where you are, 120 to 150 days til that rig produces one barrel. To the extent we're bringing on these rigs here at the end of the year, you won't see the effects of those basically til the second half of the year, those new rigs.

Really what it amounts to is, we will see lumpy production growth until we can get a base level of horizontal production from the pad drilling, and that has been established in the productions going forward with a relatively large number of wells. Then, your incremental drilling campaign and new pad additions don't have as much of an effect. In the interim time, when we're building the production up, it will have a big effect.

The net-net for 2014 is, we looked at modeling on this the other day, you see a dramatic increase in production in the second half of the year, but you have to wait for a while to get there simply because all the wells are now being drilled. You do not have that base of production from pads yet established. You have to bear with us on this. It's going to take a while before we can really crank up the growth rate, just as we wait on the impact from these rigs.

That makes sense. It sounds then like that base of production, that really doesn't smooth things out until late next year and it's early 2015 you maybe start to really genuinely be smooth quarterly projections on the growth front? Am I -- is that --?

That's probably right. That's probably the right way of thinking.

One question I had -- I think it was touched on, but I wanted to follow up on it. Was on the Wolfcamp D wells, if I just look at the IP 30 relative to the peak IP 24-hour rate or tested rate, there seems like that ratio is a bit lower than in the Wolff camp B wells and some offset wells. Are you producing those wells any definitely, or is it just a function of them being deeper, higher pressure and coming on stronger, but then also coming off a bit harder, as well early on before they catch that hyperbolic decline?

I just think it's the nature of the reservoir and looking at the wells over in Glasscock County and Reagan County, that has a little bit more history. They are averaging 500,000 to 600,000 barrel type curves. They did come off a little bit faster.

As you remember, when we discussed geologically there is -- when you rank the zones, the three best zones with the oil in place are the Wolfcamp B, Wolfcamp A and the Lower Spraberry Shale. The Wolfcamp D comes in about fourth of all the various zones, but it is under higher pressure. It's a thousand feet deeper. It should point to higher recoveries.

That's why we think it's the nature of the reservoir, why it's falling off. It's still tremendous economics. Only cost about $300,000 more to drill, and it look like we have two great wells in Midland County.

Great, that's helpful. Thanks. The last one of mine, is 45 horizontal wells that are expected to be put out in production in the horizontal Permian program in the fourth quarter, how many of those are in the north or south? Do you have that split by chance?

The number is split 45, what is north and what is south in terms of POPs. Bear with us while we dig that out.

In terms of BOEs? Thank you.

Maybe the best way is to --

No, I have it. It's about one-third in the north and two-thirds in the south.

Appreciate it, guys. Thank you.

Bob Morris, Citi.

Bob?

Mr. Morris your line is open. Hearing no response we will move to a question from Robert Christianson, Canaccord.

Congratulations on this Wolfcamp D.

Thank you.

My question is was the rock quality any better on your wells versus what is over in Glasscock? Are you seeing any difference there?

Only thing, we are deeper. We do not have any of their core data, or if they have core data. I know we are deeper and we need to watch more history. So, nobody has drilled a 9,100-foot lateral over to the east side, but there is a good -- I think the best well we could find are the two Laredo wells that have a 1,380 IP and a 1,000 barrel day 30-day rate.

Obviously, if that well holds up, it's going to be a great well. It just indicates there's not that much difference. If you take that out another 30%, that would put it up still not quite as high on IP, it'd be up close to 2,000. So, still 1,000 below, but about we are deeper. That is probably the big change.

Was there any kind of -- can you describe the completion you put on the Wolfcamp D. The amount of fluid pumped? The amount of profit, type of profit? Was your completion different than what you know of done by other guys over in Glasscock County?

I don't know what the other guys are doing, whether they are doing slick or cross length, we're doing cross length. Do you remember, Danny, what the size? Hybrid? I don't know the--

Typically for a 9,000-foot well, Bob, we would be pumping maybe $9 million pounds of profit. Up here we're using principally brown sand and doing, say, 35 stages, 35, 37 stages. Identical, essentially though, to how we complete the As and the Bs in the Wolfcamp.

Thank you very much.

Sven Del Pozzo, IHS.

Scott, I think in the last call you mentioned something about Andrews County, like you were going to do some horizontal drilling there? Do you have an update there for us?

Yes, it should be coming on production in the next two weeks, three weeks. In the next few weeks. It's pretty close, Bob, to the Diamondback well that had pretty good IP rate. I don't have an update on their well, but we are fairly close to it. We're optimistic.

Okay. On the Wolfcamp D, again, what the other gentleman alluded to about what appears to be initially steeper decline rate on the Wolfcamp D well, but there is higher gas content so that seems a little counter intuitive. I was wondering, how long will it -- I guess you could modify the completion technique perhaps to bust up the matrix more and maybe make the decline rate a little shallower over time?

Because these are just early wells, right? I just wanted to get a feeling for the learning curve and how you approach the completion in these first couple tries versus how you might modify it later?

There's really no difference than our Wolfcamp B wells. It's really just the nature of another Wolfcamp zone and the reservoir, again, it looks like the Hutt well, which has the most history of our Wolfcamp B, it looks like it's modeling the 800,000-barrel type curve, which is just slightly below the Wolfcamp B wells and the Wolfcamp A well as shown on slide number 11.

Really, not a lot of difference. To me its higher IP is only happening for a couple of days. Then, it's modeling pretty much what the Wolfcamp A and B wells are doing.

Okay. Would you mind telling us maybe like a bottom-hole pressure number for some of these D wells?

We will have to get back to you. There is a big pressure change between the Spraberry Dean going into the Wolfcamp in the gradient.

Okay. Lastly, just basic question. I saw on the 10-K, it still says about 700,000 acres net in the Spraberry trend and in some of your presentations it's 900,000 acres. I wanted to figure out why?

It's probably just the difference in the JV of the cell due Sinochem.

Would that have been the case at the end of the, even with the latest 10-K for 12-31-2012, it's still -- I'm wondering if maybe it was the Pioneer Southwest Energy -- I thought maybe it was that, maybe full consolidation?

It's consolidated. I'll have to look at it, but I'm not sure where the 700,000 acres that you are referring to, but Sinochem would have come out in May of this year. We will have a look at it.

Okay, it's right out of 10-K. All right, well thank you, everyone.

Mo Dahhane, Wunderlich securities.

Just a quick question on the assets sale that you guys -- you sold the Glasscock assets Any plans on selling the net, or maybe some non core Midland Basin acreage?

Any questions on what? On other asset sales?

Other asset sales.

We are always evaluating opportunities over time. We generally can't comment on anything specific, but we will continue to evaluate potential small opportunities of divesture.

Okay, thanks. Second question, if you want to talk a little bit about midstream, take away capacity in Midland Basin? Last month the differential between Cushing and Midland has widened a little bit. I'm curious if you guys have any hedges in place to protect that differential?

Yes. Again, this is the second time, or maybe even third time there has been a blowout in Midland. It's a combination of doing some hiccups on the Longhorn Pipeline by Magellan. Don't have any specifics on that. I think it's pretty much close back up and running at full. They're still going to expand it from 225 BOE on up, again, next year up to about 250 BOE, 260 BOE.

They had some hiccups getting up to the full 225 BOE. Then, there was an outage at a Borger refinery up in the Texas Panhandle. Midland barrels, we don't have an exact estimate. Magellan added a couple hundred thousand barrels a day to a system that was 1.3 million barrels a day coming out of the Permian Basin, so it's still very, very tight, and will be tight until the next pipeline comes on mid 2014, and then two more in the first half of 2015.

So, every time there is a hiccup and things -- it blows out. We have -- pretty much we sell all of our either through Magellan down in the Gulf Coast or to Cushing less $1.75. We are protected on most of our crude with those blowouts.

Very helpful. Thank you so much.

James Sullivan, Alembic Global.

Just had a quick question on the cost of the D wells. You guys talked about $300,000 more than the A and B. Is that a target or is that the actual cost that it was to drill these three wells.

That was actual.

That's actual, okay. Obviously, operators who are perspective for all three zones over to the east have been deemphasizing the D of decline, just because of the sense that the returns are going to be less compelling given that they were going to be a lot more expensive to drill, but seems like you guys are doing it at a much tighter -- relatively low amount more than the A and B wells. They're pretty intensive completions. You talked about 35 sections in those. Is there anything specific that you guys are doing to keep the costs down?

It's only another 1,000 feet of drilling. It's just vertical well you are talking about, vertical well extension of 1,000 feet and the number of stages since you're pumped very similar to any other zones. It's really not that significant.

All right. But, the pressure is greater so you guys are putting more in, so I guess none of that is making enough of a difference. Okay. That's great.

Then, just very quickly, on POPs in Q4. You guys did disclose in the slides that you had done 11 POPs in the Eagle Ford in September. I wonder if you guys could give us any sense just so we can get a little more confidence around Q4 production, how many October POPs you had in Eagle Ford or even in the Wolfcamp?

Yes, we had roughly -- we're talking about 90 POPsfor the quarter. We probably have, give or take one or two, because I don't have the last couple days of October, roughly 25 POPs.

25 POPs in the Eagle Ford in October?

25 POPs combined.

25 POPs combined? And, they're roughly --?

I can tell you in that 179 BOE, both the Spraberry/Wolfcamp and the Eagle Ford production numbers have moved up significantly from where they were in the third quarter.

Okay. Great. Then just last one. There is a little bit of discussion in the last call about whether the A and the B benches were going to be differentiated in any way. I know that you guys haven't drilled any more A bench wells, and you are not due to until early next year.

Is there any bit of incremental data point, other than what you guys have shown on the slides, for the Hutt A well? Anything that gives you a sense that those are going to be substantially different from one another? Or should we just think of those as being more or less look alike laterals right now?

It should be the same.

Okay. Great. Thanks for staying on so long, guys.

Eli Kantor, Iberia Capital.

A quick clarification in comparing the spacing assumptions using your resource potential pie chart and the results discussed in last night's release and in the recent presentation. What lateral length are you guys assuming in the pie-chart estimate? What is the best apples-to-apples comparison with the in-field test that you recently disclosed?

7,000 feet in the pie chart and that was all on 140-acre spacing. As we mentioned, as Tim mentioned, we are going down to 77 acres and down eventually to 50 acres, 40 acres to 50 acres.

Okay. Thanks. That's all I had.

At this time, I would like to go ahead and turn the call back over to Mr. Scott Sheffield for any additional or closing remarks.

Again, thanks. I know it was a busy morning for everybody. A lot of people on the competitors, with their calls. Again, thank you very much. We look forward to seeing you all out. Have a happy holiday over the next few weeks and we'll see you in February. Thank you.

Thank you. That does conclude our conference call for today. We do thank you all for your participation.