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Pioneer Natural Resources (NYSE:PXD)

Q3 2013 Earnings Call

November 05, 2013 10:00 am ET

Executives

Frank E. Hopkins - Senior Vice President of Investor Relations

Scott D. Sheffield - Chairman and Chief Executive Officer

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

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

Analysts

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

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

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Will Green - Stephens Inc., Research Division

Michael Hall

Robert L. Christensen - Canaccord Genuity, Research Division

Sven Del Pozzo - IHS Herold, Inc.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

James Sullivan - Alembic Global Advisors

Eli J. Kantor - Iberia Capital Partners, Research Division

Operator

Welcome to Pioneer Natural 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 website 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, sir.

Frank E. Hopkins

Good day, everyone, and thank you for 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 area 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've 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. But we can say that we still expect it to close by the end of this year.

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

Scott D. Sheffield

Thank you, Frank. Good morning. Third quarter adjusted income of $176 million or $1.26 per diluted share on Slide #3. We had third quarter production of 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 putting -- getting wells on production, shutting in some of the offset wells in the Eagle Ford Shale area. This led 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, 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 our well results. Obviously, we're very, very excited about the Wolfcamp D, what a lot of people call the Klein 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 5, 6 days ago, IP-ed over 3,000 barrels a day, 3,156, 69% oil with 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 been producing, we had an IP rate of 2,128 and a 30-day average rate of 856, 69% oil. We're seeing about 5% to 6% less oil, obviously more gas in these D wells and primarily due to a bit more mature leading to a little bit more gas, rich gas. And thoroughly, 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 type curves could be for these 3 wells in a later slide. Obviously, we're excited about the D, it sort of puts it in regard to a development mode play in addition to the successful B and A wells.

Going into Slide #4, an update on our Wolfcamp B intervals. Again, we had a successful Hutt well. Turns out it's the highest IP rate in the Midland Basin to 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's fairly close to our Mabee well, and it had an IP rate of 979. And what's interesting about this well, it didn't have the high peak. You'll see later in a type curve, but it's been flat, and 74% oil and looks like it'll be very, very similar to our other good wells, producing a lot more water.

And again, I think our -- all these wells, especially the wells with several months of production data are, obviously, we're moving toward 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 the results from the lower Spraberry Shale and then also the Jo Mill wells that just came on production over the last week. It takes about 30 to 45 days for these zones to peak. We didn't anticipate giving out results in these wells until February.

We have 13 horizontal wells in production with 3 of these wells currently flowing back, 7 wells awaiting completion, another 5 wells currently drilling with the 5 rigs. We're running 5 rigs now. As we mentioned earlier, we'll be adding 3 more rigs, obviously, we're continuing to test the various zones. We'll actually will be drilling later, early next year a middle Spraberry Shale well, where we saw recently that Diamondback announced a successful well, the middle Spraberry Shale. We expect to increase the 10-plus rigs. Let me emphasize the plus rigs that'll probably be more, we'll come out with the final number in the February call and also the annual budget for 2014.

Slide #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, so we staggard in 12 upper and lower B wells. We also tested 77-acre spacing, Tim will talk more about future downspacing going into 50 acres in 2014.

In Eagle Ford, we 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 due 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 of over 1,600 barrels a day equivalent. This will add substantial amount of incremental locations as we develop the Eagle Ford on primarily in Cairns and DeWitt in that area. We also, as we have discussed over time, some of you all, we've discussed the -- announced the agreement to sell Alaska assets for $550 million to Caelus. We expect to close by year-end or early 2014, and that capital will go back in to developing the Wolfcamp and the Spraberry out in West Texas, primarily in the North. Debt-to-book went down from 22% to 21% in the first quarter.

Going to Slide #6. Really the most important point here is that we underspent during the year on cash flow. The key point here is that cash balance actually built up from about $700 million last quarter up to $744 million at the end of third quarter. And 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 having potentially more rigs than 10 going into the North.

Slide #7 on annual production growth. We've tightened our guidance down to 172 to 173, with a 14% production growth. As you can see, with this slide and also the next slide, our lower interval range for fourth quarter, 179,000, where we're already there today at 179,000. Range is 179,000 to 184,000. Again, the increase in POPs is important, that we're adding almost over twice as many POPs wells being put on production, both Eagle Ford and the Spraberry/Wolfcamp interval fourth quarter as compared to the third quarter. We also had a pickup 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, and primarily in the Wolfcamp zones. I think you'll see us come out with a much higher growth rate than we did with the 14% this year. And again, due to pad drilling and due to the science in West Texas, we'll be focused on moving toward the higher end of the number of 13% to 18%, as we move into future years.

Going to Slide #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, and so we're going to 90 for the fourth quarter. That's why we're seeing already a big uptick in production, 179,000 in the range of 179,000 to 184,000, this does take out Alaska as discontinued operations.

Going to some of our type curves on Slide #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 type 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. So obviously, we're excited about that well. So obviously, 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, it looks like it's going to be exhibit something above a 500,000-barrel type curve. These wells do start off a little bit higher gas-oil ratio in the 1,500 to 2,000 versus the Wolfcamp basin D at around 1,000 gas-oil ratio.

Looking at some -- the map on Slide #10, you can see we did step out 50 miles. We essentially took the better wells of Apache and Laredo out to the East and Glasscock County and also in Reagan County as compared but stepping out it shows how prolific and the potential of the Wolfcamp D, so we're excited about the future development of this zone, in addition to the Wolfcamp A and B wells.

Slide #11, again, an update on the curves of the Wolfcamp A and B wells. I think to note, we've added 2 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 5 miles away from the Mabee well, we cannot fully explain the reason for more water production. So obviously, we could not get a high peak rate, but it's already in line with the 800,000-barrel type curve or higher. As you can see the green curve essentially flat production over the last 40 days.

Going to Slide #12 then returns, just to update everybody on these returns. This is strictly the northern horizontal Wolfcamp program, ranging in type 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 than 1 year. This is based on $95 oil flat, $4 gas flat and a 7,000-foot lateral with a low cost of $8 million. Even though down south, with JV was Sinochem, we're getting our wells down to $7 million already. We're assuming there will be a little bit more in this deeper area at about $7.5 million, and then we got room for any wells such as the Wolfcamp D, which will cost us about $300,000 more to drill those wells. We covered by an $8 million well cost. So with no science, obviously, with $8 million, pretty much into the pad drilling mode. So again, great returns.

In summary, on Slide 13, again, another great quarter for us. Proven up the Wolfcamp D, I think, has been the big highlight, announcing the largest Wolfcamp Shale B well interval in the Midland Basin, the downspacing, we're brining on our 12-well downspacing pilot, downspacing to 60 acres in the JV area. Again, continued downspacing in the Eagle Ford with a very successful upper Eagle Ford Shale well and 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.

Timothy L. Dove

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

So I'll start on Slide 14, that's just covering the northern Spraberry/Wolfcamp acreage drilling plan. And as shown here, it looks like we'll spud a total of about 34 wells this year 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 5 rigs in the North really near the end of the second quarter. It will be a 10-plus in early 2014 as Scott mentioned. So 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 was again regarding the activity in the North. This graph will -- this slide will cover all the status of the wells that are either drilling, awaiting completion or flowing back. And actually in the text, all of that information is enumerated. I would add one thing to that and that is we have a couple of important wells coming on here actually in the next couple of 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 here this week. In addition to which we'll be flowing back a lower Spraberry Shale well in Andrews. So these wells in terms of performance are coming at us, and 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. And the main message there is that our drilling activity is now being dispersed across the leasehold. For example, we're showing that we'll be drilling our first well in Glasscock County here in the fourth quarter. And you can see we're not just concentrating on so-called sweet spots. We are spreading around the campaign, around the acreage to be able to learn what we can and learn the areal extent of all these intervals. Importantly, we are moving further towards pad drilling. In fact, the majority of these wells will be drilled on 2-well pads. Of course, that has the effect of increasing the spud to POP times as you have to drill the wells and complete both well before you can put them on production. So it can be out in, let's say, 150 days, which leads to the sort of production lumpiness that we actually saw in relation to Eagle Ford in the third quarter.

We will have the 10-plus rigs spudding by early 2014. Of course, 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. And so that has to be worked through in terms of back-weighted production growth forecast in 2014. But 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 that the wells came on. Basically as expected, it depends, of course, where you drill the wells in the acreage, but our average is essentially on target. We're currently running 8 rigs in the South, drilling about 100 wells this year. After 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 slick water and hybrid fracs as to which direction will 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 9,000, 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 a 20% cost increase, and that trend will continue going into 2014, in fact, our average lateral length as currently calculated for 2014 is estimated to be somewhere between 9,300 to 9,400 feet for the whole campaign next year, and 100% of those wells will be drilled on pads in 2014. And as a result of that, we're going to have the same effect, we've been mentioning earlier regarding the fact that as we ramp up the rigs, we'll see some lumpiness to production just as we've described in other areas.

Let me turn now to Slide 17. We're 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're 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 a campaign of having drilled 12 wells on 3-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, and that's 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 we're actually looking down the horizontals, we call it the Gun Barrel view. And you can see what we're doing here in terms of altering the spacing on staggered laterals. So the 116-acre spacing that'll be more the traditional way, the red dots, at about 720-feet space. Now we're looking at downspacing, this most recent campaign to 480 feet or about 77-acre spacing. And so far, the results look very encouraging. It's going to take more time, of course, before we can make any specific statements about whether this is the optimal spacing. But that said, we are planning in the early or mid-part of next year a further downspacing to about 310 feet, which will be about 50-acre spacing. So we are on to the notion that we've got to understand this before we set a go-forward plan. It's a really exciting pilot project. The objective of which is to know where we go with spacing in 2015 in the forward plan. And 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's very important to watch in terms of the future of the drilling campaigns.

In terms of Slide 18, as a result of all the activity, that I've 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 5 rigs until very late in second quarter. So the main effects of that we'll begin to see -- 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. And so we anticipate the fourth quarter is 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. And 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 our vertical production decline rate ends up being about 10%. So as we ramp up horizontal drilling, especially with higher 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. So needless to say, we're very excited about how our Spraberry and Wolfcamp drilling campaign is unfolding and there's lots more to come.

On 19, turning to the Eagle Ford. For the first time, we'll be talking here about the results from downspacing in the 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 1,000 feet apart to now 500 feet or about 60-acre spacing. And that's shown in the map here is we're doing that 3 specific areas. Having done this work we believe we already can say we will be able to add 300 locations in our liquids-rich areas due to the downspacing. We've tested quite a large number of wells on 3 and 4-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 frac exhibit probably 20% more EUR potential than those that are single well drilled. And really, what it amounts to is you're getting a much more effective stimulation of the rock in this area by virtue of doing zipper fracs that are relatively close to each other. This provides a better fracture network.

As I turn to Slide 20, this gives you a depiction in a similar vein than we did with the Giddings area, looking down the wellbores at the configuration. This configuration as to the vertical spacing and the horizontal spacing differs depending upon 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 liquids-rich oil. So the spacing depends on where you are, but now we're 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 looked. But as you take a look at the gun barrel views, what you notice is we have drilled our first upper Eagle Ford wells. The 1 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. And that well, as has been the case in all of our Eagle Ford wells, has been choked back. It's only producing today on a 864 choke. And so it had potential, obviously, to do significantly better than that. But we choke back these wells for longer term benefits related to their ultimate resources or reserves.

So basically, what we're 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 interval. The combination of downspacing and the potential for the Upper Eagle Ford Shale zone, we're adding to our drilling inventory, specifically in our liquids-rich areas.

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 as already been mentioned by Scott, we went to a higher percentage of pad drilling to the near the -- during the third quarter, actually went to where we're driving 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 an effect in pushing back production in the increased pad drilling or when you increase number of wells per pad. The other factor that comes into place is as we get into more pad drilling in 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 -- the total production in the field shut-in, but we were fracing offset wells in the downspacing test. So when you're shutting 8% of your production voluntarily, you can kind of see the result that we got being somewhat expected. However, as we get into the fourth quarter, be increasing our POP rates, Scott already mentioned that, to about 45 wells. So I do expect Eagle Ford to go get back on its growth trajectory in the fourth quarter.

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

Richard P. Dealy

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. And we had aggregate unusual items totaling $0.01. So adjusted for those 2 items, we are $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, as Tim talked about daily productions, so I'll 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. And then 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 on 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've seen storage and supply continue to grow. Looking at the bottom of the slide, you can see under the columns the impact of our derivatives portfolio. And 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 5 quarters, it's been fairly consistent on our total production cost per BOE. Specifically when you look at the third quarter, the third-party transportation cost, those were higher during the quarter due to some one-time charges associated with transportation in the Eagle Ford Shale area. And then if you look at base LOE, we we're up slightly for the quarter, primarily due to higher saltwater 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 it does exclude Alaska, which we expect to be in discontinued operations for the fourth quarter, so daily production as Scott mentioned of 179,000 to 184,000 BOEs per day. It 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.

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

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from Charles Meade with Johnson Rice.

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

If I could try one on the Wolfcamp D just to start out with, obviously, that's -- that O'Daniel well, is a fabulous rate but looking at all 3 of them together, it strikes me that there's a wider dispersion of your results in that zone between the best and the third well than we've seen in the other zones. I'm curious is there -- has that -- is that been a point of discussion for you guys internally? And 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?

Scott D. Sheffield

No. Charles, if you look at the -- there's not too much difference between the Hutt D well and the O'Daniel well. The Hutt D well is a shorter lateral, they need to move it up about 30% on that rate. And so there's probably about 200, 300 barrels a day difference between the 2 wells. So it's not as big as you think, and so it's probably less than 10%. So to me, the Hutt well would've been on 9,100 feet. It would've been up in the high 2,000s. So it points toward the Midland County area has always been the best county for vertical drilling. And it just shows again that the Midland County wells, I think, are going to be the strongest wells. There are some other operators in Glasscock, that's coupled from the Laredo over there. But we're still very, very excited about Midland County, it's a little bit deeper. The well in Martin County is a pretty good step up. So we need to drill more wells South of the Scharbauer, see and get more wells to see if the -- as you go North, are you going to make a 500,000-barrel type curve? A lot of the wells and look at other investor presentations, other operators, they're saying the Wolfcamp B, a decline is going to do somewhere around the 500,000 to 600,000 range. So we've got 2 good wells, and if you normalize them, they're going to be very close to each other. So I still think we have a big area, probably in southern Martin, maybe all of Midland and some in Glasscock.

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

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

Scott D. Sheffield

Exactly.

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

Got it. And then the second question, the other -- I know you guys have mentioned that, 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, but I thought one of the really positive things here was this 20% EUR uplift with a zipper fracs you're doing over there. And I'm just curious, are you also trying to zipper fracs down on this downspacing pilot in the JV area of the Wolfcamp? And 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 to the line?

Timothy L. Dove

Yes, Charles, this is Tim. I think it's pretty clear from our data since we've been the zipper fracing with so many Eagle Ford wells that we have, we have been able to establish this 20% uplift. And I think as I've mentioned when I was covering those slides, it has to do with -- we think improved fracture network. And basically what it amounts to, if you take a look at microseismic on this, and these wells are relatively close together, you're really pulverizing a huge amount of rock in and around the wellbores. And there's a lot of connectivity as a result. So I think that, if you, say you look at the technical data we look at, it's pretty clear, we have a much higher density of events occurring around the wellbores when you're doing zipper fracs and relatively downspaced wells. And I think, 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 just too early to know. But 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.

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

And, Tim, just to hit one quick detail. Are you doing it on that -- on your downspacing pilot in the JV area right now?

Timothy L. Dove

Precisely. All those wells are zipper-fraced.

Operator

Next we'll hear from Doug Leggate with Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple also, if I may. So, 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. But they're pretty well spread out. So I guess, well my question is what can you say at this point about the repeatability across your acreage? And I've got a follow-up, please.

Scott D. Sheffield

Yes, I think as I said, I think that the general area of 800,000-plus was going to go from the Giddings area, and that general area in northern Upton County, up throughout Midland County and up to the maybe up in Martin County. And we do not yet have the wells over in Glasscock County but, obviously, it's a great area. Our driver unit, it's a mother 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, so we'll have a marker there. It's right in the center of the entire area. So we think it'll eventually apply the 800,000-plus will apply to that general area.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

Scott D. Sheffield

Yes, as I stated and when I mentioned the 10-plus rigs, look at the plus side, we're going to come up with more rigs than 10, obviously, with our cash in the balance sheet. And looks like we'll have the strip at $94, $95, and we're pretty much essentially hedged at $94, with the downside of $94 next year, with 85% of our crude. And so we're looking, at obviously, running more than 10 rigs. Obviously, I mentioned also '14 was supposed to be another year of science. I'm having these type strong wells in the A, in the B and the D, 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% in return. So we're going to focus a lot more the rigs up in the north on the A and the Bs and the Ds and drilling pad drilling. So when we come out in February, we'll come out with our CapEx and our long-term 3-year production growth rate in '14 through '16.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. And forgive me for belaboring this point a wee bit, Scott, but these are obviously very strong well results you reported, but it doesn't seem to be translating yet to the production performance. Is that just a function of, did you say the science or the sportiness of where you're bringing these things on? How would you account for that? And when would you expect it to become more ratable?

Scott D. Sheffield

Yes, remember, we were just running 1 rig in the horizontal Wolfcamp in the north early part of the year. We moved to 5. We're just now moving to 8. And so we're going to be starting the year with 10, probably much -- probably higher than that. And so you've got the ramp-up in the North with the rigs. I think, you have the science on essentially every well we're drilling in 2013 in the North. So that's the big item. So we pretty much have a very good picture of what's happening in Eagle Ford going into next year, and we have a very good picture of what's happening in the joint venture area with Sinochem. And so the North is our big swing factor. And obviously, that's where the focus is going to be on more pad drilling, more development drilling and stretching out the science through '15 or even '16 in some of these zones.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

So can you give us the -- as to where the growth rate goes, Scott?

Scott D. Sheffield

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

Operator

And next we'll hear from Dave Kistler with Simmons & Company.

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

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

Scott D. Sheffield

Yes. The -- in regard, it's the same number we're giving out for the 50 billion barrels resource potential for the entire Midland Basin and the Spraberry/Wolfcamp zones. Remember, we're only adding 4 zones. We're using a very conservative ultimate -- 140-acre spacing, so Tim's already talking about 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 2 Spraberry zones, which we didn't include. So our numbers are going to go up significantly, along with the 50-billion-barrel number. It's going to go up significantly over time.

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

Great. I appreciate that color. And then thinking about the rig cadence you were talking about in the northern Midland Basin, that 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?

Timothy L. Dove

Dave, it's Tim. Just to let you know, we do have 2 external frac crews working only on our vertical wells today. So all the horizontal campaign's being pumped by Pioneer wells or 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. And that -- 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. And as a result, we never really wanted to be 100% vertically integrated anyway. It was a product of dropping the vertical rig count. So I think we get -- we'll have a lot of comfort in bringing on some third parties to pump the incremental wells.

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

Okay. Appreciate that. And then one follow-up on that. When you think about the savings generated from your vertical-integration efforts, what do you kind of estimate right now that's saving you guys on a per well basis?

Timothy L. Dove

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

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

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

Timothy L. Dove

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

Operator

And now we'll take a question from John Freeman with Raymond James.

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

You mentioned the 15 vertical rigs that you're running in the Spraberry field, that you'll likely start to reduce that going forward and shifting more to horizontal drilling. I just want to make sure that I'm understanding correctly kind of 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. So initially, you can drop a couple of rigs from the 15 to 13. And then maybe, if I'm thinking about it right, a couple of years down the road, maybe you start to replace some of those remaining 13 vertical with some horizontals to satisfy some of the obligation. Is -- am I thinking about that right?

Timothy L. Dove

You're on the mark. You're pretty close. Well, I think 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 of continuous development. So I think if you look at this, the next few years, there's a -- there's a plausible scenario, we actually have 0 vertical rigs running within the next few years.

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

Okay, great. And 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 just be how much time is related to the science? And then in the south, the 150 days, where do you think that could go to over next couple of years? And I'll stop there.

Timothy L. Dove

Yes, I think if you take a look at it, the -- if we're dealing with 150 days in the north, that's related to probably roughly 30 days plus related to science. And so when I think, you look at our southern target for 2014, it's more of like 120 days, 115, 120 days. So that's where I count for the science. In the south, we're basically not doing science anymore, is what it amounts to. It's about 30 days plus worth of science time.

Operator

We'll now take a question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to follow-up on a comment you made with regards to 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. And I wanted 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 less attractive economics relative to these 3 zones at the Spraberry? Or you're just kind of waiting, waiting for more details? And could you develop 4 zones simultaneously, would be a follow-up on that.

Scott D. Sheffield

Yes, Brian, it's strictly the outperformance of the A well and also the D wells. So we knew the B was going to be good, but the outperformance of the A well and the D wells, and the focus will be on the A, B and D, 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, so essentially we have low to no data on the Spraberry. We do know that the Spraberry has lower pressure. There's lots of oil there. It'll probably produce. We have to get our well cost down, and we need more history. So we're just -- it's going to be hard to beat wells paying out less than a year. And so it's the focus on the A, B and the D, what will focus most of the activity. So we're increasing the number of A, B and D wells next year versus our previous plan of going to '14, there'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 '15 and '16.

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Scott D. Sheffield

In a long-term model of the next 5 years, we see a couple of 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 and they do reduce operating -- they average with your higher operating cost vertical wells. And they ultimately do lower operating cost on a per BOE basis.

Brian Singer - Goldman Sachs Group Inc., Research Division

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

Scott D. Sheffield

The dollars over about a 5-year period, so you pick up a little bit each year.

Operator

And our next question comes from Leo Mariani with RBC Capital Markets.

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

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

Timothy L. Dove

Yes, I think 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. But the answer is yes, we'll be looking where we can drill longer laterals. I think if you look at the cost, though, in the north were deeper, of course, and so we show a cost, of roughly $7.5 million to $8.5 million. Now that's for 7,000-foot laterals and, of course, it has to do with the incremental depth. I think you add a few hundred thousand when you get up to about 10,000 feet, maybe $400,000, $500,000. So you will incrementally be adding a cost, typically about 20% additional cost, 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 lateral going from 7,000 to 10,000, that's some 40% increase. So that 20% increase in cost becomes relatively insignificant concerning the amount of incremental production.

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

Okay. That's helpful. And I guess, just terms of some of these wells you announced, you guys 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 guys gave with the package of well results, it looks like some of those were down kind of 50-ish percent versus 24-hour rates. Just kind of any color you guys have potentially on sort of those declines. Is that kind of following your type curve at this point? I mean, with some of the bigger fracs you put on it, do you think it's giving you a higher IP? Just any thoughts on what that could lead to in terms of longer-term EURs here?

Scott D. Sheffield

Yes. 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, and that's 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'll have several more, eventually, to compare it. But obviously, it's working with that well. So we don't have enough data to the north yet. But 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 an increase in reserves follows.

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

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

Scott D. Sheffield

Exactly. We'll see a proportionate increase as we start increasing our laterals in the north, with a corresponding increase in well cost. But you still get a big pickup in regard to less well cost increase versus the increase in production and the increase in reserves.

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

Okay. That's helpful. I guess in terms of the Upper Eagle Ford, obviously, there's only 1 well on production at this point in time. Are there Lower Eagle Ford wells directly offsetting that particular well on tight spacing? And if so, any thoughts on communication or it's early?

Timothy L. Dove

Yes, we do have offsetting Lower Eagle Ford wells in the area. I think it's the case, in fact, there's 5 lower offset Eagle Ford wells in the area. And then as a result, I think we can 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'd expect from the Lower Eagle Ford well. And so far, really no communication, so that's a positive right now. So it means we possibly can go to this lower downspacing to the 300 feet, and that would be -- it has a good chance to be successful and add more locations.

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

Okay, that's helpful. And I guess, just on the southern JV acreage, obviously, you've got stacked wells in the B zone, upper and lower. I mean, longer term, do you think there may be communication there? Are you seeing any evidence at this point?

Timothy L. Dove

Too early to say. Those wells were just put on production here, I don't know, it's a couple -- 2, 3 weeks ago. So we -- we're not going to be able to outline sort of the net effects of the downspacing in a very granular fashion probably until 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.

But 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. And so that's the hope, but it's too early in that case as compared to where we are in Eagle Ford.

Operator

We'll take a question from Matt Portillo with TPH.

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

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. And then as you mentioned, early indications or, I guess, as you've built more data on the production on the southern wells, any indication on kind of how EURs are trending in the southern part of the play?

Timothy L. Dove

I think, first of all, on the well cost, I think it was more in terms of the overall program, and I mentioned earlier that the program's going to average, say, 9,300 to 9,400-foot laterals and that's basically $8.5 million in our plan. So that's -- you can sort of ratchet it up, of what's actually a 10,000-foot lateral. So that's the way I'd be planning it.

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

Okay. And then in regards to kind of corresponding EURs, how are you thinking about the EURs on those well?

Timothy L. Dove

Yes, the EURs, if you remember in the south, we have an average of 575,000 BOE. That range is, of course, depending upon where you are in the south. To the extent you're in 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. So the average of 575,000 is still holding up. That's based on a 7,000-foot lateral. So to the extent we actually can extend these laterals out as we've been talking about, we will probably bumping that, but we need to drill some more wells before we're able to establish that.

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

Great. And 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? And is this something that you may look at in 2014?

Scott D. Sheffield

Yes, I think, obviously, we're probably going to be maintaining roughly the same rig count over the next few years. That the current levels. We do have to get approval from our partner, Reliance, but we're looking at maintaining the same rig count, and we're confident that we'll continue to grow it over the next 3 to 5 years.

Operator

We'll take a question from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

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

Timothy L. Dove

Well, 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 these areas, you're actually drilling the Upper Eagle Ford 100 feet above the Lower Eagle Ford well. And so, you can make the case that, that would be tapping into and completely filling the need to complete the whole, say, 300 feet in the Eagle Ford. However, as you get up higher in the section, I think, it's definitely the case that we'll see some contribution from the Austin Chalk.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then just one 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 1 section where you could potentially have 30-plus wells into 1 section to see the viability in potential communication?

Timothy L. Dove

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 of these wells drilled in 2014 and know what that would look like. In other words, it's along the line of what Scott said. Would it be A, B, D combo set of drilling? Would it be the Spraberry zone, a Jo Mill zone, just the Lower Spraberry zone? That's what we're doing right now, in the case of our drilling campaign, is understanding what that would look like. I think that's a 2015 project.

Operator

Now we'll hear from Gil Yang with DISCERN.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

The O'Daniel well was really pretty spectacular. Maybe can you comment -- I know you don't have a 30-day radio, but can you just sort of comment on, off of that IP? Are they -- is it sort of tracking what the other wells were doing?

Scott D. Sheffield

Yes, it's still making over 2,000 barrels a day after about 5 days. So you can sort of plot it yourself and still outperforming the -- all the Cline wells, the D wells and really over the B wells also.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

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

Timothy L. Dove

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. So the O'Daniel B well, just so you know, has just been put on production, and now the D well is put on production, whatever Scott said, 5 days ago. These were wells that were drilled back-to-back. So it doesn't have to do with D results, just O'Daniel D was drilled where it was.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. Was there any reason why you chose O'Daniel -- those 2 -- the O'Daniel spots drill those wells? Or that's...

Scott D. Sheffield

It's for 2 simple reasons. One, it's a 100% working interest. And it's right in the center of the area we've been drilling between the Glasscock play and also the Hutt area. So to prove up the center part of the acreage.

Timothy L. Dove

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

Operator

We'll take a question from Will Green with Stephens.

Will Green - Stephens Inc., Research Division

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 led 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?

Scott D. Sheffield

I think that the only difference is the D wells, I'm excluding the D well up in Martin County. We only have 1 result up there. It was 60% oil. But the other 2 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. So a little bit higher gas-oil ratio. It is about 1,000 feet deeper. A little bit more mature, probably, it's a little bit more gas, but it's not, it's insignificant when you look at the economics. It's a difference of 69% and 74%.

Will Green - Stephens Inc., Research Division

Sure. And the rates looked great, and so I don't want to discount that. But the EUR -- on the EUR expectation, you think that, that holds pretty steady? I mean, do you think we settle out in kind of the 60- to 70-year range? I know you guys had a slide that broke out kind of your early wells tracking low 70% in terms of oil cut for the EUR? I mean, is that a good expectation?

Scott D. Sheffield

Yes, we need more history on the D, and I don't remember what the wells off to the Glasscock -- in Glasscock County you're doing, what they're holding. We'll have to research that, of other operators, but we just need more history to determine that. But the gas-oil ratio in generally most of these zones will tend to increase a little bit with time.

Operator

And now we'll hear from Michael Hall with Heikkinen Energy Advisors.

Michael Hall

A lot of mine has been asked and answered. One thing I just wanted to clarify, I guess, on just and see if I'm thinking about it right. As it relates to the whole lumpiness and results flowing through -- wells flowing through to quarterly results, it sounds like we probably continued to have the effects of this lumpiness through at least the first half of next year. But perhaps, as you get to scale the program fully ramped up, we'll see some smoothing out of that lumpiness in the second half of '14, and not only into '15. Am I thinking about that correctly?

Timothy L. Dove

Yes, I think it's a combination of factors, Michael. One is we're still increasing the rig count. So that will happen between now and the end of the year and into next year. And so everyday, you bring on a rig to start doing pad drilling, you now can set the clock for, depending upon where you are, 120 to 150 days until that rig produces 1 barrel. Okay? So 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, until the second half of the year, those new rigs. And really, what it amounts to is we'll see lumpy production growth until we can get a baselevel of horizontal production from the pad drilling, and that's 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. But in the interim time, when we're building the production up, it will have a big effect. So what the net-net for 2014 is, we looked at some modeling on the other day, you see a very 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. And you do not have that base of production from pads yet established. So you have to kind of 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.

Michael Hall

That makes sense. And so I guess it just sounds then like that base of production, that really doesn't smooth things out until late next year in sort of '15, maybe start to really generally be kind of smooth quarterly progression on the growth front, right?

Timothy L. Dove

That's probably right, that's probably right.

Michael Hall

Okay. And then, I guess, one question I had, I think it would -- kind of touched on it, but just wanted to follow-up on it, was on Wolfcamp D wells. If I just look at the IP 30 relative to the peak IP 24-hour rate or tested rate, those seemed like that ratio is a bit lower than in the Wolfcamp B wells and some offset wells. Are you producing those wells any differently? Or is it just a function of them being deeper, higher pressure and sort of they're coming on stronger but then, also, coming off a bit harder, as well, early on before you touch the hyperbolic decline?

Scott D. Sheffield

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're averaging 500,000 to 600,000-barrel type curves. They do come up a little bit faster. As you remember, when we discussed geologically, there is -- when you rank the zones, the 3 best zones with the oil in place are: the Wolfcamp B, Wolfcamp A, the Lower Spraberry Shale. So, the Wolfcamp D comes in about fourth of all the various zones. But it is under higher pressure, it's 1,000 feet deeper, and so it should point to higher recoveries. And so that's why we think it's the nature of the reservoir why it's falling off. But it's still tremendous economics; only cost about $300,000 more to drill, and it looks like we have 2 great wells in Midland County.

Michael Hall

Yes, great, that's helpful. And then last one of mine is just the 45 horizontal wells that you put on production in the horizontal Permian program in the fourth quarter, how much of those are in -- how many of those are in the north versus the south, do you have that split, by chance?

Timothy L. Dove

The number is 445 what's north and what's south in terms of POPs. Bear with us for a second, we'll try to dig that out. Maybe the best way is to...

Scott D. Sheffield

No, I have it, I have it, yes. It's about 1/3 in the North and 2/3 in the South.

Operator

And now we'll hear from Bob Morris with Citi.

Hearing no response, we'll move to a question from Robert Christensen with Canaccord.

Robert L. Christensen - Canaccord Genuity, Research Division

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

Scott D. Sheffield

Only thing, we are deeper. So we do not have any of their core data or if they have core data. But I know we're deeper, and we need to watch more history. So nobody's 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 2 Laredo wells, that have a 1,380 IP and 1,000-barrel-a-day 30-day rate. So obviously, if that well holds up, it's going to be a great well. So that -- it just indicates, there's not that much difference. So if you take that out another 30%, that would put it up still not quite as high on IP. It would be up close to 2,000, so still 1,000 below, but we are deeper. So that's probably the big change.

Robert L. Christensen - Canaccord Genuity, Research Division

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

Scott D. Sheffield

I don't -- I don't know what the other guys are doing, whether they're doing slick or cross-link. We're digging cross-link. Remember Danny with the size -- hybrid, yes.

Timothy L. Dove

Yes.

Scott D. Sheffield

I don't know the --

Timothy L. Dove

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

Operator

We'll take a question from Sven Dell Pozzo with IHS.

Sven Del Pozzo - IHS Herold, Inc.

Yes, 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?

Scott D. Sheffield

Yes, it should be coming on production in the next 2 weeks, 3 weeks, in the next few weeks. It's pretty close-by to the Diamondback well, that had a pretty good IP rate. We don't have an update on their well, but we're fairly close to it. So we're optimistic.

Sven Del Pozzo - IHS Herold, Inc.

Okay. And yes, on the Wolfcamp B, again, the -- what the other gentlemen alluded to about what appears to be initially steeper decline rate on the Wolfcamp B well. But there is higher gas content, so that seems a little counterintuitive. I was wondering how long will it -- I guess, you could probably modify the completion technique, perhaps, to bust up the matrix more and maybe make the decline rate a little shallower over time? Or because these are just early wells, right? So I just wanted to get a feeling for the learning curve, and how you approach the completion in the first couple of tries versus how you might modify it later?

Scott D. Sheffield

There's no really no difference in our Wolfcamp B wells. And so, it's really just the nature of another Wolfcamp zone. And the reservoir, again, the -- it looks like that the Hutt well, which has the most history of our Wolfcamp B, it looks like it's on the -- 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 #11. So really not a lot of difference, so to me, I guess, this higher IP is only happening for a couple of days, and then it's modeling pretty much what the Wolfcamp A and B wells are doing.

Sven Del Pozzo - IHS Herold, Inc.

Okay. Would you mind telling us like a maybe like a bottom whole pressure number for some of these -- for, well, B wells?

Timothy L. Dove

Look at that, yes.

Scott D. Sheffield

We'll have to get back with you, but there is a big pressure change between the Spraberry-Dean going into the Wolfcamp, in the gradient.

Timothy L. Dove

Right.

Sven Del Pozzo - IHS Herold, Inc.

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

Scott D. Sheffield

On the -- which page is it on?

Richard P. Dealy

Spraberry versus the [indiscernible] Basin, I think. The JV area, gross versus net.

Scott D. Sheffield

Okay. It's probably just the difference in the JV, with the sale to Sinochem.

Sven Del Pozzo - IHS Herold, Inc.

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

Richard P. Dealy

No, it's consolidated so that -- I have to look at it but the -- I'm not sure what the 700,000 that you're referring to. But Sinochem would've come out in late this year, so we'll have a look at it.

Sven Del Pozzo - IHS Herold, Inc.

Okay. Yes, it's right out of 10-K.

Operator

And now we'll take a question from Mo Dahhane with Wunderlich Securities.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

Just a quick question on the asset sale that you guys -- now you sold the Alaska assets. Any plans on selling net or maybe some noncore Midland Basin acreage?

Scott D. Sheffield

Any questions on what? On other asset sales?

Timothy L. Dove

Other asset sales.

Scott D. Sheffield

Yes, we're always evaluating opportunities over time. So we generally don't -- can't comment on anything specific, but we will continue to evaluate potential small opportunities of divestiture.

Mostafa Dahhane - Wunderlich Securities Inc., Research Division

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

Scott D. Sheffield

Yes. Again, this is the second time or maybe even third time there's been a blowout in Midland. It's a combination of doing some hiccups on the Longhorn pipeline by Magellan. I don't have any specifics on that. But I think it's pretty much close back up and running at full. They're still going to expand it from 225 on up again next year, up to, I think, about 250, 260. So they had some hiccups getting up to their full 225. And then there was an outage at a border refinery up in the Texas Panhandle. And so Midland barrels, we don't have an exact estimate but Magellan added a couple of 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-'14 and then 2 more in the first half of '15. And so every time there's a hiccup and things -- it blows out. But we have pretty much -- we sell all of our -- either through Magellan down to the Gulf Coast or to Cushing, less $1.75. So we are protected on most of our crude with those blowouts.

Operator

We'll have a question now from James Sullivan with Alembic Global.

James Sullivan - Alembic Global Advisors

I just had a quick question on the D -- 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 3 wells?

Timothy L. Dove

That's actual.

James Sullivan - Alembic Global Advisors

That's actual. Okay, because I know that, obviously, operators who are respective for all 3 zones over to the east have been deemphasizing the decline just because kind of the sense that the returns are going to be less compelling, given that there were going to be a lot more expensive to drill. But it seems like you guys are doing it at a much tighter -- much relatively low amount more than the A and the B well. I mean, they're pretty intensive completion. You talked about 35 sections in those. Is there anything specific that you guys are doing to keep those costs down?

Timothy L. Dove

But, it's only another 1,000 feet of drilling. It's not -- that's a vertical well you're talking about, vertical well extension of 1,000 feet, and the number of stages, essentially, are pumped very similar to any other zone. So, really, it's really not that significant.

James Sullivan - Alembic Global Advisors

Right. But -- and the pressure is greater, so you guys are putting more in. But -- so I guess none of that is making enough of a difference. But, okay, that's great. So 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 can give us any sense just so we can we can get a little more confidence around Q4 production, how many October POPs you had in the Eagle Ford or even in the Wolfcamp?

Scott D. Sheffield

Yes, we had roughly -- we're talking about 90 for the quarter. We probably had -- give or take 1 or 2 because I don't have the last couple of days of October, roughly 25.

James Sullivan - Alembic Global Advisors

25 in the Eagle Ford in October?

Scott D. Sheffield

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

James Sullivan - Alembic Global Advisors

Okay, great. And then just last one, there's a little bit of discussion in the last call about whether the A and the B ventures were going to be differentiated in any way. And I know that you guys haven't drilled anymore A bench wells. You're not due to, I think, until next year, early next year. But is there any bit of incremental data point? I mean, other than what you guys have shown on the slides for the A -- 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?

Scott D. Sheffield

It should be the same.

Operator

And our last question will come from Eli Kantor with Iberia Capital.

Eli J. Kantor - Iberia Capital Partners, Research Division

Just a quick clarification in comparing your spacing assumptions using your resource potential pie chart and the results discussed in last night's release and in the recent presentation. What lateral lengths are you guys assuming in the pie chart estimate? And what's the best apples-to-apples comparison would be infield test that you recently disclosed?

Scott D. Sheffield

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

Operator

And 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.

Scott D. Sheffield

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. I 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.

Operator

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

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