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Pioneer Natural Resources (NYSE:PXD)

Q3 2012 Earnings Call

November 01, 2012 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 and Chief Operating Officer

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

Analysts

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

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Eli J. Kantor - Iberia Capital Partners, Research Division

Sven Del Pozzo - IHS Herold, Inc

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Operator

Good day, everyone, and 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 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 26.

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. I want to first give a shout-out to all of our friends on the East Coast and especially those in the New York City area, please continue to be safe and we hope you're all able to recover quickly from the devastating storm that impacted your area earlier this week.

With that, now let me briefly review the agenda for today's call. Scott will be the first speaker. He will provide the financial and operating highlights for the third quarter of 2012. He'll then follow up by giving you an update of the company's production growth outlook and capital program for this year. He will then provide a progress report on our joint venture negotiations for the horizontal Wolfcamp Shale and provide some color on our planned divestiture of our Barnett Shale properties.

After Scott concludes his remarks, Tim will discuss our drilling results and plans for the horizontal Wolfcamp Shale, the Spraberry vertical and the Eagle Ford Shale. He'll also comment on the 2 horizontal wells we drilled to test the Jo Mill interval in the Spraberry field, and he'll update you on the upcoming winter drilling program in Alaska. Rich will then cover the third quarter financials in more detail and provide earnings guidance for the fourth quarter. And then after that, we'll turn the call over to the people on the call for questions. With that, I'll turn the call over to Scott.

Scott D. Sheffield

Thanks, Frank, good morning. I do echo Frank's comments about the Hurricane Sandy. Highlights on Slide #3. Third quarter adjusted income of $104 million, or $0.82 per adjusted share; our production, 159,900 barrels a day equivalent over the range that we gave out for guidance for the third quarter. When you adjust it for the Barnett Shale going into discontinued ops, we were 153,000 barrels a day equivalent. Above the end of the -- top end of the range of 155,000 to 159,000 barrels a day. Production over the last year, up 33,000 barrels of oil equivalent per day, or 28%; and also the oil growth is up 52% over the last 12 months.

From second quarter 2012, oil growth is up 5%, production's up 10,000 barrels a day, or up 7%. Again, strong growth primarily attributed to Spraberry vertical program of going deeper, horizontal Wolfcamp Shale play and the Eagle Ford Shale drilling programs. We're continuing to see tremendous performance from going to the Strawn, the Atoka and the Mississippian and co-mingling with the Spraberry Wolfcamp zones in all of our deeper vertical drilling in the Spraberry field. And again, continue to see strong Eagle Ford performance and achieving record production levels.

We're narrowing our 2012 production growth guidance range from 25% to 29%, to 27% to 28% based on year-to-date results. That's taking the Barnett Shale out for discontinued ops. When you add that back in, we're at the high end of that range of 28% to 29%.

Going to Slide #4, our highlights. We continue to see tremendous success from our successful horizontal Wolfcamp Shale program and our southern 200,000 acres are meeting essentially our type curve of 575,000 barrels of oil equivalent. We're continuing to drill at wells now in Midland County, we'll be going to Martin County shortly, which Tim will talk more about as we move up north.

We'll talk more about our joint venture. We're pursuing the joint venture partner to accelerate our horizontal Wolfcamp Shale development in our southern 200,000 acres. The data room is still open today as we speak. We're increasing our 2000 (sic) [2012] drilling budget by $100 million primarily to accelerate the horizontal Wolfcamp Shale appraisal activity. We essentially have a -- started a fifth horizontal rig drilling the Midland and Martin County horizontal wells and we actually had a 6th rig for a period of about 30 to 45 days drilling 2 very successful Jo Mill wells, which is in the Spraberry section in our Spraberry Trend Area field. We had 1 well over 550 barrels of oil equivalent per day. It's still increasing, both wells are still increasing. And essentially, the Jo Mill has been our main producing formation for the last 30 to 40 years and essentially covers our entire 900,000 acres. Very, very excited about those results.

We announced our Barnett Shale divestiture. The data room is open, allows us to reallocate capital. In addition, the last 2 months, when oil ran up about 30 days ago, we have added several hedging positions from 2013 to 2015 and added more gas positions from '14 and '15 using primarily 3-way collars. We expect to call our convertible senior notes, 2038, that are due 2038 for redemption, the first time we have that right in early in 2013 on January 15 based on a September 30 closing stock price of $104.40. Conversion of the notes would result in paying $480 million in cash and issuing 3.3 million shares. The $480 million cash we would just borrow off our facility. The interest rate would go down from 2 7/8% to approximately 2%. In addition, our last VPP will be running out at the end of December, it expires at the end of 2012, provides 3,500 barrels of oil a day, increased production volumes and without increasing our op costs.

Slide #5, our continued strong production growth continues in 2012. And again, our range going into the fourth quarter is 154,000 to 158,000 barrels a day. We're taking Barnett out. In addition, we're showing a 27% to 28% range, but when you add Barnett in, we're essentially at the high end of 28% to 29%, again, driven by the Spraberry vertical program, the horizontal Wolfcamp program and the Eagle Ford Shale program during 2012. We also note, we've gone up from 47% liquids in 2010 to 61% liquids in the third quarter.

Going to Slide #6 on capital spending and cash flow. Our capital program, as I mentioned already, we increased the drilling capital by $100 million from $2.4 billion to $2.5 billion primarily by the 5th horizontal rig drilling in Midland and Martin County, and also we drilled a -- we had a 6th rig for a period of a few weeks drilling the 2 Jo Mill wells. Funded by all the items below, combination of the cash flow, equity proceeds, liquidated derivatives and inventory reduction, credit facility borrowings to balance it in regard to cash flow spending.

An update on the Wolfcamp Shale joint venture opportunity. As you recall, we're offering anywhere from 1/3 to 50% of Pioneer's work interest in the southern 200,000 acres. It's over 4,000 potential horizontal development locations. It does exclude downspacing. The -- we're currently drilling on 140-acre spacing. Most of these oil shale plays are going down to somewhere between 50 and 60 acres, so that's additional upside. It's a 2 billion-barrel gross resource potential; liquids content about 90%; and again, our type curve is 575,000 barrels of oil equivalent for a 7,000-foot lateral. Tim will talk more about some recent activity on some longer laterals. And a great IRR of 45% at $85 oil and $4 gas. We've had participants from all over the world come in to our data room. It's been open about 2 months. We expect bids in the month of December and we expect to announce a successful JV opportunity during the first quarter of 2013.

Going to Slide #8, an update on the planned Barnett Shale divestiture; 120,000 net acres, 2/3 are located in the liquids-rich Combo Play of the Barnett Shale. We reported third quarter production of 7,000 barrels of oil equivalent per day. We're already up over 8,000 barrels of oil equivalent per day, being 55% liquids, a combination of oil and NGLs; 181 wells on production; over 1,100 total locations to drill. We currently have 1 rig operating, continuing to grow production with just 1 rig, and the reason is we're allocating the capital to Pioneer's higher return core assets in South Texas and West Texas.

Data room just opened this week. We expect bids in the month of December and expect again to announce the successful divestiture during first quarter of 2013.

Last slide, investment highlights, on Slide #9. Pioneer now has a -- just a total U.S. asset base. We have one of the highest exposures from proved reserves and estimated net resource potential of over 7 billion barrels of oil equivalent. Again, the 2012 drilling program, in going forward, focused on the Spraberry vertical deep program, the horizontal Wolfcamp Shale program and the Eagle Ford Shale program. The joint venture obviously will allow us to greatly accelerate going to '13, '14 and '15 the horizontal Wolfcamp Shale program on the joint venture properties. Again, the Barnett Shale divestiture will allow us to reallocate capital to our core assets in South and West Texas. Tremendous strong production profile; vertical integration continuing to improving returns; again, attractive some of the best hedged positions in the universe for 2012, '13 and '14 for the company; and again, a strong investment-grade financial position allows us to move forward. Now I'll turn it over to Tim to go over the operating results.

Timothy L. Dove

Thanks, Scott. First, starting on Slide 10, we'll give you an update regarding how the horizontal Wolfcamp drilling campaign is going, and suffice it to say, we continue to focus our drilling in the oval area, the southern 200,000 acres shown on the map, where we're focused on holding 50,000 acres that would otherwise expire by the end of 2013. Accordingly, we need to drill and have on production about 90 wells by then. We're well on track to get that done. We've already drilled 27 wells and have 17 of those on production. I'll show you some more data on those wells shortly.

Currently, we're running 4 rigs in the southern area, a total of 5 rigs. And I'll touch on the additional rig drilling to the north in a minute. We are going to be increasing the rig count to 7 by the end of the year, and those rigs are already contracted. As to the northern activity, this is the first wells we'll be drilling in Midland County. You can see approximately where the drilling is occurring by virtue of the arrow on the map. Those -- we are just in the process of drilling 2 wells, they're about 750 feet apart. The first will be in the A zone, and the second in -- sorry, the first will be in the B zone and the second will be in the A zone. The first of those has already been drilled. And actually, we're rigging up on the second well as we speak. When both of the wells are done, they'll both be frac-ed essentially back-to-back. And so I anticipate we'll have results regarding these wells during the February earnings call.

As Scott mentioned also, we'll be marching to the north of that point, probably drilling a couple of wells in Martin County, perhaps followed by wells in Gaines County. The idea is to prove up our substantial acreage position in the north. And we believe these areas will be prospective in the horizontal Wolfcamp Shale. We're still targeting a minimum of 7,000-foot laterals and we're testing longer laterals. In fact, we just recently drilled a 10,000-foot lateral in about 19 days. So where we have the leasehold, you'll see us extending the laterals significantly beyond 7,000 feet.

We have also been successful in drilling what we refer to as development-style wells. Those are wells that do not have any science. It would be more akin to what we'll be drilling as we develop the field, and we've actually confirmed that we can drill those for about $7 million. A lot of the reason we can do it relatively cheaply is the fact we're using 85% Brady Brown sand from Premier Silica, our sand mine in Brady, Texas, and that's a tremendous cost savings for us.

I'll now -- I'm going to turn to Slide 11. We've got a lot of detail on this slide showing the recent drilling results in the Wolfcamp Shale horizontal play. I'm certainly not going to read all this data to you, but as I mentioned, we've drilled 27 wells in the southern 200,000 acres, of which 17 are on production, 10 were added during the third quarter. All 17 are shown on the map. Now what we're showing on this map is data pertaining to 24-hour IP rates. That normally would not be what we would do because we really believe that 30-day peak rates are much more indicative of the ultimate well performance. However, the reason we're showing 24-hour IP rates here is -- the fact is, several of these wells, in fact 10 recent wells, haven't been on production long enough to be able to establish a 30-day rate. So we thought the best thing to do at this point is to show 24-hour IPs because it's the only way to have an apples-to-apples comparison of the well results. When you look across the board, most of these wells are drilled in the B zone. Specifically, as you look to the northwest, those are the Giddings wells. Those are really phenomenally strong wells. In the mix here, we have a predominance of B wells. 15 of the 17 are B wells, but 2 are in the A interval. One of those was drilled in the center part of the map, a very strong well, 585 BOE per day. We also drilled 1 well to the north and east that was actually drilled into a fault. This was a well that was drilled prior to our acquisition of 3-D seismic in the area. And as a result, it was drilled in a location we otherwise would not have drilled had we had the 3-D in advance.

However, having drilled it into a fault, it's really unable to get a substantial frac on this well, and therefore, the results are, as expected, poorer than what you would normally look for out of the A zone. We're very positive on the A zone. In fact, we've got 2 more wells that are actually been drilled and are waiting on a frac. It's probably going to commence very shortly, later this month. And those 2 A wells are showing actually a University of 10, and they'll have about 7,500 foot laterals.

So I can say definitively this drilling has gone exceedingly well. You can tell because if you look at Slide 12 and compare the production from these wells, particularly 12 wells here where we have adequate amount of historical production data, that the wells are doing very well in terms of lining up versus our type curve pertaining to the 575,000 BOE, and this is the oil portion, of course. But the orange line shows these wells that have been on for quite a long time are tracking beautifully with that type curve. Actually, if you look to the green line, these are the 2 Giddings area wells that I mentioned on the prior slide. And one of those wells, the Giddings 2041 has just reached its 1 year anniversary from first production a couple of weeks ago, and it's produced 133,000 BOE. To give you a frame of reference, our typical Wolfberry vertical well would normally make 140,000 BOE in a 40 or plus year period of production. So this bodes well that we really are on the mark in terms of our type curve. The production is coming in very nicely on these wells on average, and we're very pleased to say that the horizontal Wolfcamp play continues to meet our longer-term expectations.

On Slide 13, this is just a depiction of our view that there will be upwards of 5 potential zones in the horizontal Wolfcamp play as we develop the drilling campaign from the A all the way through the D as shown on the log. And you'll see us be drilling 5,000 to 10,000 foot wells in various of these zones as we go forward. We have as yet not even drilled a well into the Wolfcamp C, for instance. And the only Wolfcamp D well we've drilled was in Midland County well over a year ago.

Shown here, the vast majority of the wells are in the B currently, 15 wells currently on production and the 2 A wells I already mentioned having been drilled and ready to be completed shortly. We are also testing for the first time a lower B Wolfcamp well. And we'll -- this is just an example of us continuing to go down the learning curve in terms of all the intervals that we can access in the horizontal Wolfcamp play.

Importantly, we drilled a couple of very highly successful wells in the Jo Mill Sand, which is, as you see on the log, just above the Lower Spraberry Shale. We've drilled thousands of vertical wells of course over the years that drilled through and completed in the Jo Mill, so we have an immense amount of data. These 2 wells were only drilled at roughly 2,500 feet laterals, but they've made excellent rates. And as Scott mentioned, these rates are actually increasing, but over 550 barrels a day on a BOE basis and another one over 300 BOEs per day. So we got some work to do as a result of these successful wells, and that is to pursue an analysis of the well results and what they mean in terms of where we go with the Jo Mill. We're taking core in this well and we'll tie it to petrophysics and we plan 2 additional wells to follow up. It does prove to us though that the area where the vertical wells were drilled, this is in basically northern Upton County, that these vertical wells in the area, were not adequately draining the zone, and that gives us significant running room for the future in terms of Jo Mill horizontals. It's just another example indicating that the Permian Basin horizontal potential is really in the very early stages of understanding in terms of all the various zones for which horizontal drilling will be available.

And in our case, since we control the vast majority of the acreage, it really bodes well for the future of horizontal drilling in the area.

That said, if you turn to Slide 14, you start looking at our production performance in the Permian Basin, you can't forget the contributions from vertical deeper drilling. In fact, about 2/3 of our wells access resources below the Wolfcamp. And as shown and particularly related to the average IP rates of these wells, that we can add anywhere between 120 and -- have 120 to 180 BOE per day wells versus your typical Wolfcamp completed vertical which make typically 90 barrels a day on IP. So we know we're adding a lot of reserves and a lot of potential to these wells. And perhaps, the deeper drilling can add, in various areas, up to 100,000 BOE above that 140,000 BOE Wolfcamp-related type curve. And vertical drilling is the key to performance.

And if you look at Slide 15, you can see it very clearly. The results we see here are predominantly due to the impact of the deepening and the impact on our overall performance. In fact, we came in at about 69,000 BOE per day in the third quarter and that allows us to tighten our range and actually move it to the top of the range to 67 to 67 -- 66,000 to 67,000 BOE per day for the year. And you can see our fourth quarter range of about 69,000 to 71,000 BOE.

Just a little bit of detail on what happened during the quarter pertaining to the NGL situation. You may recall, we built quite a large inventory of NGLs in the second quarter pertaining to Mont Belvieu fractionation limitations. So in the third quarter, we did draw down about 1,800 barrels a day from that inventory. However, we did have a production loss due to the fact that we had these constraints due to the ethane rejection. As a result of that, we had about 90,000 barrels still in inventory. However, that will be principally offset by the fact that we have line fill requirements for the new Lone Star NGL pipeline, taking our Permian volumes down to Mont Belvieu in the fourth quarter.

The other effect we're seeing is as offset producers and ourselves continue to drill a significant number of wells. We're getting to the point where our Spraberry gas processing facilities are nearing their capacity as we get near the end of this year. And that has an effect to us of actually not causing ethane rejection per se, but reducing recoveries of ethane. Essentially, as the plants get more full, ethane recovery rates go down. In other words, you're just less efficient in the plants. So we're going to lose probably 1,000 to 2,000 BOE per day due to reduced ethane recoveries in the plants. That will be alleviated, of course, as the new driver facility is put in place at the end of the first quarter, early second quarter, another 100 million cubic feet a day capacity adding to the existing 260 million. In addition to that, there's another 100 million a day plant due to be put on production probably in the end of next year or early in the following first quarter. We are running currently 25 vertical rigs.

Turning now to the Eagle Ford Shale, well, suffice it to say, we set a new production record in the third quarter, as Scott already mentioned. On Slide 16, we have a recap of the activity. We drilled 38 wells in the quarter, and put 35 on production. As I mentioned, last quarter, we're back-weighted a little bit this year. We had more wells being put on production in the second half than we did in the first half and that's leading to outstanding production results. And we're on schedule and on pace to drill the 125 wells planned this year, with only a very small handful of those targeting dry gas as expected. We continue to push the envelope in terms of the use of white sand as opposed to more expensive ceramics. In fact, the well results look very strong for the use of white sand and we think we'll continue to push that envelope. We have actually been drilling dry gas wells with white sand as well to help reduce the cost of the wells. And if you look at the net cost savings, it's something like $700,000 to use white sand as opposed to ceramics. So we'll continue to push the technical envelope because of the significance of the cost savings. We're essentially built out with our CGPs. We have a couple more to build next year, but essentially, with 11 online, we've got a great first mover advantage in terms of processing our volumes.

We've also improved efficiencies, if we turn to Slide 17. The depiction here is showing the drilling cost per foot decreasing substantially, in fact, about 18% over the last 5 quarters or so, while at the same time, the drilling feet per day is increasing -- has increased about 28% over the same time period. It goes to show, as we continue to learn more and continue to push efficiencies, that we'll be also hopefully controlling and/or reducing well costs.

Looking at Slide 18, here's another reason to expect we can do so. In 2012, this year, the predominance of the wells as shown about 70% -- we're drilling primary wells or primary acreage to hold the acreage as we went through the process of drilling to preserve a leasehold that would otherwise expire. We're coming to a close on that as we get to 2013. In fact, next year we'll be about 80% multi-well pad drilling as opposed to single-well drilling up and down the space. And so that's going to give us a tremendous cost savings of probably $600,000 to $700,000 per well going into 2013. That will be somewhat offset by the fact that we probably will be using bigger fracs as we improve efficiencies, as well as increased lateral lengths going forward. And one more additional concept we're using in the field is choke management as shown on Slide 19.

I won't go into all of the details here other than to say you should look at this slide and notice the green line, it's the smallest of the chokes being used and what these lines depict is cumulative production from the wells under different choke sizes. And what you can see is with a 12/64 choke, the cumulative production crosses over the lines of the larger chokes within about 5 or 6 months. And that has the effect of, I think, increasing longer-term EURs of the wells and does reduce production declines in the wells, especially in the early time frame. And ultimately, what it's doing is sustaining higher wellhead pressure and enabling more stable flow within the well. So this is actually proven, I think, and we'll continue to use choke management to make sure we're improving the EURs of these wells. Ultimately, on Slide 20, it's -- the proof's in the pudding on production and the results of all the efforts of our South Texas team has led to record production in the field. Again, about 29,000 BOE per day during the quarter. And here again, it leads us to move up to the top of the range, the forecast for the year to about 27,000 to 28,000 BOE per day and about 32,000 to 35,000 expected in the fourth quarter.

Well, you can tell how well we're doing just by checking out public data, particularly from IHS. And if you study that data across the whole trend, you can see that the Pioneer wells are exceeding expectations and our strong well performance is one of the reasons this production growth is doing so well. In fact 50% of our wells are in the top quartile of all the wells in terms of EUR drilled in the Eagle Ford Shale. And at the same time, 80% of wells are above the median EUR, the mean, and so this just goes to show that our wells are among the best. We think we're in one of the best areas in the Eagle Ford and that's the reason that these wells are performing so well.

And finally, the last slide for me is Slide 21, it's on Alaska. Our production has done very well. Our N1 well, that was the Nuiqsut well with a mechanically diverted frac from last year, continues to produce well and is leading us to actually have pretty good production results this year from Alaska. We continue with 1 rig on the island. It's drilling Nuiqsut and Torok wells. We're going to follow up that successful mechanically diverted frac-ed Nuiqsut 1 well that was frac-ed last year, with a total of 4 wells to be frac-ed this winter season. 3 of those will be Nuiqsut wells, 1 will be Torok wells. To prove out that, that style of frac actually is the way to go and it will lead to a lot of running room for our Alaska operations. We'll start tracking those wells probably in February or so and will take a couple of months to do that. And as a result, we won't see any results on this until well into the second quarter. But the fact is, I think we're going to have some good success here frac-ing these wells with Lower 48-style completions. We're also in the midst of planning and are ready essentially to drill a second Torok well from the shore. Recall last year, we drilled quite an excellent well from the shore, it exceeded our expectations. And we're drilling an offset to that well this winter and progressing a pending future development from the shore and in the FEED study that's ongoing. We think as a result of the well we drilled last winter, we've added about 50 million barrels of oil or so in terms of resource potential to the Torok.

So it was a great quarter of operation. I give credit to all our operations teams for their performance and particularly a couple of teams we haven't even discussed, that being Raton and West Pan and Hugoton. Those contribute also mightily to strong performance that enabled us to beat our production forecast for the quarter.

With that, I'm going to pass it over to Rich, and he can discuss the third quarter financials and the fourth quarter outlook.

Richard P. Dealy

Thanks, Tim, I'm going to start on Page 22. Net income attributable to common stockholders was $19 million or $0.15 per share. That did include unrealized mark-to-market derivative losses on an after-tax basis of $146 million or $1.19 and included 2 unusual items, significant items. One, discontinued operations, as you guys are familiar, we did close our South Africa sale in the third quarter, and so this reflects the effects of that during the quarter. We did have, on a pre-tax basis, about $29 million gain on that sale. So the $32 million on an after-tax basis was included in earnings or $0.26 per share. Also, as we talked about -- back in August, we did unwind some 2014 and 2015 gas derivatives. And we also unwound some interest rate swaps so we recognized a gain of $28 million after-tax or $0.23 related to that. So adjusting for the mark-to-market unusual items, we're, on a clean basis, at $104 million or $0.82 per diluted share.

Looking at the box in the middle of page, the guidance, as you recall, included Barnett Shale activity and so we wanted to put it on a comparative basis with actual results. So the middle column there is our results, including Barnett Shale, but excluding the unrealized mark-to-market derivative losses and unusual items.

So Scott and Tim both talked about production did extremely well at 160,000 BOEs a day for the quarter. Production costs above guidance range, I'll talk more about that here in a minute. And then if you look at the rest of the items, for the most part, they're in line with expectations for the quarter -- as we went into the quarter.

Turning to Slide 23, on price realizations. Looking at the bar charts there, you can see oil. We're up 1%, so essentially flat for the quarter. NGLs continue to have weakness, so we were down 5% on the NGL front. And on gas, as you guys have seen the forward curve move up, we're up 30% relative to the second quarter, up $2.62 for realized prices. At the bottom of the slide, you can see the impact of the VPPs. As Scott mentioned, that does go away up to the end of the fourth -- this quarter, so looking forward to that being done and gone and adding the 3500 BOEs a day back into production. And then you can see the impact of derivatives at the bottom as well.

Turning to Slide 24, talking about production costs. Production costs for the quarter were up $1.54 per BOE. It's principally related to lease operating expenses in West Texas. As you guys know, the activity level's high out there, so we have mainly 4 items that impact us for the quarter. Higher salt water disposal costs I'll talk a little bit more about; higher electricity costs associated with the 30% increase in gas prices, which is used for power generation out there; higher repair and maintenance costs for the quarter; and then as Tim talked about the -- on a per BOE basis, losing the 4,000 BOEs per day of sales during the quarter impacted us on a per BOE basis. On the salt water disposal costs, we did have 2 salt water disposals that were hit by lightning during the quarter that caused incremental hauling, which was at a cost as well as incremental third-party disposal costs. And so those have both been fixed and those are behind us. But to further address the growth in the field, we have added 3 new disposals out there during the month of October and we've drilled 6 more disposal wells. They're in various stages of completion, but they should be up and running by the end of this quarter or early in 2013. So that should help bring these costs back to a more normal basis as we move into the first part of next year.

Turning to Slide 25. Guidance for the quarter. All this guidance does exclude Barnett, reflecting discontinued operations. Scott and Tim both talked about daily production for the fourth quarter being 154,000 to 158,000 BOEs per day. Production costs we have moved up the range just to reflect some of those costs will still roll into the fourth quarter before we see less salt water disposal costs going into the second half of the fourth quarter and in the first quarter. The rest of the items here are consistent with past guidance, I'm not going to go through each of those individually, but they're there for your review. And so with that, why don't we open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And for our first question, we go to Dave Kistler with Simmons & Company.

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

Looking at the Jo Mills wells that you reported, can you give us any flavor for kind of costs and maybe what you guys are thinking about with respect to IRRs? And then lastly, you made comments about it doesn't seem like that area is depleted from the vertical drilling. If you think about the 800,000 to 900,000 acres you referenced, do you feel confident that, that's something you can deploy across the whole portfolio?

Timothy L. Dove

Well, first of all, on your first question on cost, we've done some work -- of course we had a bunch of science on those first 2 wells as you might expect, so we've done some work to look at normalizing the cost of the wells, excluding science. If we were to be in that 2,500-foot range, I think we would say they would be $4 million to $4.5 million. You start moving them out to 5,000, which I think will be the next wells we drill, will be 5,000-foot wells, they look like they're $5.5 million. In terms of aerial extent, as I mentioned, the Jo Mill is ubiquitous across the play. We need to do a little bit more work of course from a petrophysical standpoint. But what we really need to do is identify the sweet spots. And every shale play, of course, has sweet spots, and it's true of this play as well, although, this is a silty sandy zone, it's surrounded by shales. And so we just need to do some more petrophysics to exactly know where to go and where the sweet spots are going to be. But suffice it to say, since the -- the Jo Mill we've completed several thousand wells. We've got the data. We just need to do the work on it, Dave, to understand exactly where we're going to go with it. But it's a material well, set of wells, considering they came in well above our expectations for 2,500-foot laterals. So we're pretty excited about it.

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

And just kind of thinking about that relative to the IRRs and the rest of your portfolio, it would seem like, based on those production numbers, that, that would be probably one of the more attractive things you're pursuing right now.

Timothy L. Dove

Yes, you'd have to say that, although, I think at this point in time, we'd say we don't have much data, we don't have much time under our belts on these wells. So we really don't have an EUR estimate, and we certainly don't have an EUR estimate pertaining to longer laterals in the Jo Mill. So I mean, on the surface of it, with this kind of production, at least in the early stages, the economics look positive.

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

And then maybe a cleanup question. With respect to the Barnett Combo divestiture in your guidance, you take the production out of your forward forecast, but it doesn't look like CapEx is adjusted for that. When we think about the CapEx increase, am I thinking about that correctly, that CapEx is still in there and it represents maybe what percent of the $100 million?

Scott D. Sheffield

Yes, the CapEx is still in there.

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

What percent of the $100 million increase would maybe be captured by that?

Scott D. Sheffield

0. That's all Wolfcamp. $100 million increase, strictly Wolfcamp, primarily.

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

And then just one last cleanup item. With respect to the $7 million well costs you talk about in the Wolfcamp, how does that increase when you start looking at 10,000-foot laterals?

Timothy L. Dove

Yes. The $7 million as is depicted on the slide is for a 7,000-foot lateral. I think you get, if you're at 10,000 feet, right in the $8 million to $9 million range, something like that. We're drilling the wells very fast though. As I said, 19 days on a 10,000-foot lateral is pretty impressive. So I think it's a couple of million more once you go out to 10,000 feet.

Operator

And for our next question, we go to Cameron Horwitz with U.S. Capital Advisors.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Tim, you guys talked about last quarter on the Wolfcamp, horizontal Wolfcamp, flowing those wells, upcasing before putting on artificial lift. Did you do that with this last batch? And how are you kind of seeing -- are you seeing any kind of early indications there are difference in well performance?

Timothy L. Dove

Right now we're actually focused on one particular style of completion, and that is the 200,000, 250,000 barrels of water, 7 million pounds proppant, 85% Brown sand, blowing the wells up, up tubing, gas lifted. That's basically the style today.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

And then -- I know you briefly touched on it in the Jo Mill formation, but can you give us maybe just a quick compare and contrast on the rock properties there versus what you see in the Wolfcamp?

Timothy L. Dove

Well, again, the Jo Mill, is a sort of sandy, silty zone. It's more of traditional reservoir pay zone as opposed to a shale. What we needed, we've done some microseismic on that well, and it's very clear that the well has access, by virtue of the frac, probably some of these nearby shale zones. We have shale above and below the Jo Mill. We are doing a lot more science to understand that, but I think we're actually accessing reserves in production, not just from the Jo Mill per se, but also from some of the nearby shales. It's going to take us more time to really get our arms around that, but clearly it's a significant resource. As Scott mentioned, the Jo Mill is one of the primary zones in vertical drilling over many, many years. It and the upper Spraberry have over 50% of the well in place in the traditional way the wells used to be drilled. It's a large resource. And what I think we've proven, as I've mentioned, is we really haven't been adequately draining it with 40-acre wells. Now compared to shales, you have much better reservoir rock here. So you're landing the wells in the Jo Mill in the reservoir rock and perhaps -- we're studying this more -- actually accessing some of the shales with the frac.

Operator

We go next to Leo Mariani with RBC.

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

Just question here on, sort of, rig counts. You talked about going down to 25 rigs in the Spraberry vertical program. Is that kind of the spot we would expect it to stay into next year? And I guess you guys talked about going to 7 horizontal rigs in the Wolfcamp by the end of the year. Do you see that increasing further next year? Obviously, it sounds like you're getting ready to get pretty decent cash infusion from the Barnett, as well as the Wolfcamp JV. I'm just trying to get a sense of how you might deploy that money.

Scott D. Sheffield

Yes, Leo, we're going to wait until we get our answers in December. I've looked at the current whole [ph] strip going into 2013 and forward, and make a final decision on both the horizontal rig count. We would expect the horizontal rig count to be higher than the 7, obviously, with a very successful joint venture. In the horizontal side, we'll have to decide how many horizontal rigs to drill up in Midland and Martin County, where we own 100% of the acreage where we're drilling now based on those tests, and then we'll back into what the vertical program should be. So at this point in time, it could be 25, but we don't know. We'll look at it. We'll announce our CapEx sometime during the first quarter, January or February of 2013.

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

Got you, okay. In terms of the Gaines well that you guys talked about, it looks like the production performance on those wells extremely strong. Have you guys put out kind of an EUR estimate for what you think the Giddings wells might be? It looks like they've kind of done sort of the 2 best wells in your portfolio there.

Timothy L. Dove

Well, they are excellent wells. I think realizing these wells are only 5,300 feet in terms of lateral length, you have to adjust for what eventually will be drilled in that area, which would be more 7,000-foot plus. But at the 5,300-foot lateral length, these wells look like they're probably 650,000 to 675,000 BOE roughly. And, like I say, I expect to the extent we drill longer laterals, we'll exceed that in that area.

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

Got you, okay. Kind of a question around the, kind of, senior convert notes that are coming due here. You guys talked about cash payment and then some shares. I just wanted to make sure, so those shares, I think you said it was 3.3 million, those are definitely going to be issued as part of redeeming those notes, is that correct?

Richard P. Dealy

Yes. How the convert works is we would pay the principal amount of notes with cash, which is the $480 million. And then depending on where our stock price trades around the redemption period, we would issue a number of shares and at the 104 level it's about that 3.3 million shares.

Operator

We go next to Doug Leggate with Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple of quick ones hopefully. If I could jump very quickly back to the Jo Mill, what are the implications on the 20-acre downspacing of a successful Jo Mill program? I'm just wondering if it's a trade-off between one and the other. And maybe some cost on those wells would be appreciated.

Scott D. Sheffield

Yes, Doug -- is that a Scottish accent there?

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I'm afraid so.

Scott D. Sheffield

Okay. I think if the Jo Mill really plays out like it could, in the horizontal Wolfcamp, then it's going to lead to more horizontal drilling and less vertical drilling over the next 5 to 10 years. So it depends on how massive the Jo Mill horizontal could be. So the question is, we're eventually going to try a horizontal Atoka, we're going to try a horizontal Mississippian, and so the big challenge, can you recover more oil long-term by drilling more horizontal wells? We don't know at this point in time, but it's something that we're going to have to look at. And so we have to be careful of how many vertical locations we drill. We know we can drill them down to 20-acre spacing safely. They're probably only draining about 10-acre spacing. The new Railroad Commission rules allows us a lot of flexibility to drill a maximum number of horizontal wells, but it does impact as we drill the current vertical well program pretty aggressively. It could impact where we put our horizontals if the Jo Mill plays out. So it's just something we're going to have to watch and drill some more Jo Mills like we plan on in 2013.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

What was your approximate cost you expect those horizontals to come in at?

Scott D. Sheffield

Tim mentioned they should be around $5 million to $6 million, depending on the horizontal length.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My second question is really kind of a double-edged one, and forgive me for this one, but I'm really interested in your discussion around choke management in the Eagle Ford. You seem to have kind of thrown yourself into the middle of a debate there because some of the, I guess, some of the aggressive operators are running sort of 34. I've seen as high as 40/64 on their chokes, and the IP rates as pretty impressive. Now you guys are coming out and saying, well, we kind of prefer this approach. Could you maybe just offer some thoughts around that? And if you could layer into that what you're doing in the Wolfcamp by way of choke management. I'll leave it at that.

Timothy L. Dove

I think the difference that we're citing is the fact that we're not really focused on IP rates. Yes, we could flow these wells really hard. We could actually be substantially increasing our current production if we just got off the concept of choke management. We're really more focused on EUR, the long-term performance of the wells. And by virtue of the data that I showed from various wells for which we're comparing choke sizes, we think it's pretty definitive from an empirical standpoint that EURs are positively affected by basically choke management. And I think higher choke sizes has the opposite effect. And so you'll see us continue to do that. We're just not really about IP rates. They really have very little meaning in terms of the ultimate recoveries of the wells.

As to Wolfcamp, generally speaking, we're bringing these wells on with I think 20/64 chokes. And then we increase them through time. But it's really not a choke management process there as much as it is just basically controlling the flow rates.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. Those 3 wells you showed in this presentation, were they all similarly completed in terms of frac stages and so on?

Timothy L. Dove

Yes. Essentially, that's the way we do this analysis to make sure that they're essentially completed the same and essentially the same lateral lengths.

Operator

We go next to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

In the Wolfcamp, the A well that you drilled, how close was the successful well drilled relative to an upper B well? Does the well say anything from the perspective of communication between zones? Or could you talk to at what point you would test an A on top of an upper B or a B -- an upper B on top of a lower B to have confidence there's not communication between the zones?

Timothy L. Dove

Well, we haven't done the latter. We have not actually drilled an A on top of a B as we eventually will if you start looking towards the future, where you have stacked laterals. In the area we're drilling the 2 new A wells, we are basically drilling an A and a B within 700 feet of each other, so we'll have a better answer as to whether we see any interference as it relates to those new A and B wells in the north shortly. But it's going to take us, of course, as I mentioned, a few weeks to get that data. But we're just now in the process of developing the concepts of drilling closer stack laterals, and we'll be able to give you a lot more data later. I mean, the fact is we have been spending a lot of money on science, we have a lot of microseismic data from these wells, and that'll be the case going forward on these northern wells. We'll be doing microseismic on those as well. We'll know a lot about frac propagation and potential for any kind of interference issues. There's a theory out there that actually frac-ing the wells and having interference might be a positive actually, but we don't know that yet. But the fact is, we'll be getting more data as we go through time.

Brian Singer - Goldman Sachs Group Inc., Research Division

And in the Eagle Ford, how are you thinking about your activity level into next year based on the efficiency gains that you have gotten, and then the conversations you're having with your JV partner given that the carries are running out?

Timothy L. Dove

We are currently the process of evaluating the budget for 2013. We haven't really determined exactly the number of rigs we're going to use. And as a result, the number of wells, really, dictated by the number of rigs. The fact is, we are getting more efficient. The whole premise of the plan for 2013 is really not based on the number of rigs per se. It's getting the number of wells drilled. I think it's very likely in 2013 we'll get by with less rigs to drill the same number of wells we otherwise had planned. But suffice it to say, that's the subject of our negotiations and discussions with our partner. Those won't be concluded until a little bit later this quarter.

Brian Singer - Goldman Sachs Group Inc., Research Division

You would expect your net CapEx then to rise given that you've got less JV proceeds coming in next year versus this year with a flat well count?

Timothy L. Dove

Yes. The carry is essentially over here at the end of 2012. And so to drill the same number of wells, again, we're focused more on wells than we are on rigs, it's going to be a substantial higher net Pioneer cost. Those dollars are already being spent as we speak, but the vast majority of those are not our dollars. In 2013, we'll be on a more of a JV basis where we'll have spending coming out of the Pioneer account.

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes. And then lastly, I know you don't want to put too many specifics on the 2013 program, but can you just talk broadly when you think about where you want your level of spending versus cash flow next year and your expectation for JV proceeds? Do you anticipate any other asset sales of meaning beyond the JV and the Barnett Combo sale, or should we think about any equity as an option next year?

Scott D. Sheffield

The answer to your last question is, as I stated in the last call, is no. And the first part of the question is, the goal is to spend the cash flow with our budget. And look at the proceeds that we anticipate to get from both the down payment, say 25% down on the JV plus the Barnett Shale, and I would anticipate that we would spend a portion of those cash proceeds over and above our cash flow for 2013.

Operator

And for our next question, we go to Brian Lively with Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Can you guys put some context around your expectations for the northern side of the Wolfcamp? And should we expect similar results to the Giddings wells adjusted for lateral length? And Scott, before you ask, yes, that's a South Louisiana accent.

Scott D. Sheffield

Both Midland and Martin County look as good as the Giddings area. It's in the center part of the basin, so all of our maps we expect and would hope would be as good as the Giddings area, both in Midland and Martin County, as we drill these wells, both in the Wolfcamp A zone and the Wolfcamp B. And so the depth -- they'll be similar depths, which gives us higher reservoir pressure, which gives us higher recoveries. So that's what we expect, but we won't know until we start producing them, so give us a few weeks to months.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Sure that's understandable. And then moving back down to the south with the various holes you punched around the southern acreage, can you guys just talk a little bit about the variability and whether or not you've -- like you've kind of proven up some core areas, tested the boundaries, et cetera?

Scott D. Sheffield

We haven't -- we just drilled -- I think Tim mentioned that we drilled what we call a couple of rocker B wells, which are the further southeast wells in the joint venture area. They'll be coming on soon, so there'll interesting tests. Most of our acreage is in what we consider the oily area. It's not in the gassy area toward more gassy, where EOG and Approach are. We are planning on some Wolfcamp D -- lower Wolfcamp zones, Wolfcamp D. I think Tim mentioned we'll have a lower, what we call a B3 or Lower Wolfcamp from the upper standpoint. It will be coming on. More A wells will be coming on, and we'll eventually be planning a C well in 2013, so we want to get all 4 zones tested. And obviously the better quality is in the Giddings, but we're still making very, very good wells in the center part of the joint venture and at the bottom of the acreage also.

Timothy L. Dove

Yes, let me just comment just briefly on one additional aspect of this and that is, it is a statistical play, so we're really looking at the mean of these wells as opposed to any individual one. But I can tell if you look at the map on Slide 11, you can see that some of the drilling to the very southwest actually has the least amount of production. And actually, that's exactly what we expected. What we're doing is drilling periphery of the acreage in the southwest. We drill actually as far as you can go on our acreage to the southwest. And as expected, the well results aren't quite as good as when you go north of there. And so what we've actually proven is our modeling and mapping is quite accurate in terms of the aerial extent of this play and the prospectivity on our acreage. So I consider that to be a positive that we're at a point where we can actually pretty much delineate the type of expectations from individual wells based on where they're being drilled. That bodes well for the future as we get out of this mode of just preserving leasehold and getting into development drilling, where we can focus on the best areas first.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Yes, that's good context. Last for me. Just in terms of the processing constraints that you outlined for the fourth quarter and the first quarter of next year, are we to expect production from that area to continue to grow, or do you think that's going to be limiting in terms of your ability to grow at least through the first quarter?

Timothy L. Dove

Well, we have, clearly, a lot of activity in the basin. That's led to these facilities getting closer to capacity. I think the fact is, as we get into the winter period, we do burn gas in the field for heating. And so I anticipate we have any kind of a decent winter, we're really not going to have a situation in which we have any kind of constraints that are all that significant. If we didn't have a very cold winter out in the West Texas area, it might be more of an issue. But I think what it will be -- we can cram more gas into the system. The real issue is as we do so, we get less efficient and we'll have lesser ethane recoveries. This is a marginal problem. We get recoveries in that plant typically at 65% or so. So they'll be moving down perhaps to 55% or 50% in the case of more capacity being eaten up by additional gas. But this is really just a marginal issue, and it could actually be alleviated by a cold winter. We'll have to see how that goes.

Operator

For our next question, we go to Charles Meade with Johnson Rice.

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

Going back to the Jo Mill, I think you guys touched on this a bit. But it sounds like those wells may have been just recently completed because the oil rate is still on the way up. Do you have a view that you'd care to share on where you think that peak 24-hour IP is going to go?

Scott D. Sheffield

Yes, we are moving lots of water also, load water. Tim didn't mention I think there, they did have smaller frac jobs in these but we are producing a lot of load water, and so we're not pumping -- well, I guess they're not -- based on the current choke size, we just can't get the system unloaded, so they're continue to increase, the total fluid continues to increase. So it's going to take a while, probably another several weeks just to watch it. So they've only been on about 2 or 3 weeks.

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

Got it. That's the color. But you don't have a sense on whether those oil rates are going to go up by another 50% or anything like that?

Scott D. Sheffield

Just a week ago, the 550 well was down about 300, so it's climbed up pretty good in the last just 7 to 10 days.

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

That's really impressive. What -- how much frac stages did you guys do on those wells?

Timothy L. Dove

Those are basically each 15 stages or so. We're pumping 2.5 million to 3 million pounds of proppant and only about 40,000 barrels of water. So this is a lot smaller frac jobs by design in the early stage of these wells, as we're trying to understand how the fracs propagate. But I think it could easily be the case as we get out to 5,000-foot wells, you're going to get into the 30, 35 stages, and we could actually get it to where these are drilled and completed similarly to the Wolfcamp wells that we're doing in the south potentially.

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

Got it. Well, that's all very tantalizing. And do you have -- I realize this may be getting a little too far ahead. I know Scott mentioned that you're going to try horizontals in some of those deeper zones like the Strawn, Atoka and the Mississippian, but do you have, kind of, a next candidate for one of the traditional field pays that you're going to try with a horizontal like maybe in Upper Spraberry or something like that?

Scott D. Sheffield

No, right now, we're just getting our handle in looking at the science, doing more geological work. And then we'll plan a couple more longer Jo Mill wells next year would be the next step. Nothing planned right now in the Upper.

Timothy L. Dove

I will tell you, Charles, as you look at the logs though in the Spraberry field area, there are quite a large number of targets that are actually shales that look nearly as good as the Wolfcamp within the Spraberry section itself. So I wouldn't put it past us, at some point, to test those, just not in the current plan.

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

Got it. And then last question. I think this will be a quick one. Is the -- as you have more ethane rejection going on, is it reasonable for us to expect the NGL price realization to move up a bit relative to benchmarks because the residual stream is more biased to the heavy end? Or is that not something that we should expect?

Timothy L. Dove

Well, I think you're still seeing a lot of drilling out here, and we're producing more ethane every day with these wells. And so the amount of ethane -- this isn't rejection per se it was referring to, it's really recovery rate -- is really not that significant compared to the new ethane being brought on production, whether it's in the Permian or the Eagle Ford or other fields, ethane production is definitely on the incline, so I don't necessarily link what's happening here at all to higher ethane prices for sure.

Operator

For our next question, we go to Eli Kantor with Iberia Capital Partners.

Eli J. Kantor - Iberia Capital Partners, Research Division

I was hoping to get a little bit more color on your Permian opportunity set. You talked about 24,000 gross vertical locations in the past. When should we expect to hear a horizontal Wolfcamp count? And I want to make sure that I understand your commentary earlier correct in that you don't expect any kind of degradation in the vertical inventory as you shift towards horizontal development, is that correct?

Scott D. Sheffield

Yes. On your first part of the question, we have. If you look at our total proved resource potential slide, we show the horizontal Wolfcamp 3.5 billion barrels of oil equivalent, 8,000 locations. And that's only giving credit for about 400,000 acres of our total of 900,000 acres. And so depending on what the 2 wells do in Midland County, those 2 wells at Midland County that we're drilling and competing soon, if they prove up, then we'll be substantially increasing that along with the Martin County wells. And the second part of your question was?

Timothy L. Dove

The effective vertical wells, the horizontals.

Scott D. Sheffield

Yes. Right now, we're still carrying -- is it 25,000?

Timothy L. Dove

23,000, yes.

Scott D. Sheffield

23,000 vertical locations. Right now, we are -- and that's high-graded substantially. Right now, we do not -- I mentioned long term. We could look at potentially the more we add on horizontal, reducing the vertical, but right now, we feel like they're very, very economical. We just have to be able to lay out a vertical and horizontal drilling program. If it turns out we're drilling 4 to 5 in the horizontal Wolfcamp, and we're drilling in the Atoka, we're drilling in the Mississippian, we're drilling a horizontal in the Jo Mill. And so the more you develop these resources horizontal, it'll lend to potentially reducing the vertical program over the next 5 to 10 years.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay, great. And in terms of your Northern Wolfcamp delineation activity, how many results should we expect on the Q4 call? And are you going to be testing both the A and the B zones, did I hear that correctly?

Timothy L. Dove

Yes, the first of the wells has been drilled. It's an A zone well. The second is a B -- sorry, I got those mixed up last time, too. The first is a B zone well, the second is an A zone well. Those are just in the process shortly here to be completed and they'll be put on production. So we will clearly have data on those 2 for the fourth quarter call. At which point we move to Martin County, start doing some drilling up there, but to the extent that you sort of roll the clock forward, we'll have very little to talk about in terms of production from those wells by the time we get to early February just because of the time required to get them on production and see some production results. So most likely, it's going to be the 2 Midland County wells. Needless to say, it'll be questionable how much data we'll really have on the Martin County wells.

Eli J. Kantor - Iberia Capital Partners, Research Division

Okay, great. And in terms of your oil field services and equipment that you have in the basin, again, as activity shifts from vertical development to horizontal development, how much of your oil field services need can be met with the 15 rigs you have in-house, the frac fleets that you have in-house, and how much will be fulfilled by third parties?

Timothy L. Dove

Well, right now, at our current rig count in the Permian basin, we're using 100% Pioneer green. And as long as we just continue at the current rig count, that would be the case. We can also accommodate the additional 3 or 4 horizontal rigs that I mentioned coming on with our existing equipment. If we were to get into a JV case that went to 15 or 20 rigs and a substantial northern campaign, we'd probably need more, and we'd probably bring in some outside services at that point. But for right now, our internal equipment is sufficing.

Eli J. Kantor - Iberia Capital Partners, Research Division

Got it. Last question for me is on the horizontal Spraberry activity in the Jo Mill. How big of a program do you expect to have in the fourth quarter in 2013?

Timothy L. Dove

Right now, we're evaluating 2 wells, and we're doing a bunch of science work, as I mentioned, in terms of petrophysics. And we actually got cores being evaluated. So we have a plan to drill a couple of wells early next year in the Jo Mill following up on these 2, probably in a different area and probably with a longer lateral length. But to say more than that in terms of activity, we really aren't going to chart out significant activity changes until we understand from several wells what the productivity of these are going to be.

Operator

And for our next question, we go to Sven Del Pozzo with IHS.

Sven Del Pozzo - IHS Herold, Inc

Basically, just got real couple of short ones. Relative to what you were saying before about being able to save on completed well costs by not doing as much R&D work for your horizontal Wolfcamp. Could you just help me to understand in layman's terms what you can afford to not do in your development-mode wells on a risk-adjusted basis that would make you feel comfortable with going into development mode without spending that extra money for, say, cores and correlational logs on the cores and so forth that you understand better than I do anyway?

Timothy L. Dove

I don't know about that, Sven, but I will tell you that as we now are in the process of finding out more and more about the different zones we're drilling, and that would include going into C drilling, into D bench drilling, upper and lower Bs, I think we're finding we have to do more science than less as we understand the productivity from those different zones. That's certainly true as you go into Jo Mill or you go into Atoka horizontal. You're going to be doing science on all of these wells, and you have to, to be able to understand where we're going with regard to how these wells are going to get completed, how the fractures are propagated and so on. But suffice it to say, at a minimum, we put $2 million extra into these wells. And the way you compute that is about $700,000 additional drilling costs, principally related to pilot hole drilling; about $500,000 for coring typically; and then about $400,000 for both microseismic and the more sophisticated logs suites. So when you're all said and done, it's a minimum of $2 million that we spend to make sure we learn what we need to about rock qualities and understanding where to go with the development.

Sven Del Pozzo - IHS Herold, Inc

Okay. And when you say moving into development mode, maybe I'm thinking that within localized areas or once you discover those sweet spots of which we already have a couple. It wouldn't be going into development mode everywhere, it would just be on an area-by-area basis across your large acreage position, where you might be drilling pilots at the beginning and then moving into a development mode in that localized area, is that fair to say?

Timothy L. Dove

That's exactly the way to think about it. There's science wells in various locations of the field because recognizing these shale plays aren't ubiquitous in terms of the quality of the rock and/or the performance. And so we do microseismic work, we do quarrying and so on to understand the rock qualities in specific areas. Once we understand that and we can tie it to the other data we have, then we're sort of done in terms of science, and we can get off into development drilling. So you're exactly right. We have to have science wells in roughly each of the different areas where we're drilling to get a handle on these properties.

Sven Del Pozzo - IHS Herold, Inc

Okay. And just more macro basis for the basin as a whole, the Midland Basin. You're seeing some Cline shale positive wells coming in Central Eastern Glasscock County then even other operators even farther north. I guess right now, are you informed enough to say anything about whether the clients also are going to work on your acreage? Or just overall, how come most of the industry operators have drilled mostly these B laterals so far in the southern Midland Basin, and we've seen more Cline activity to the northeast of you and also directly north?

Scott D. Sheffield

Yes, Sven. Our data shows that the most oil in place is in the A and the B zones. That's why we're focused on the A and B zones. The D is very prospective, but it's probably about half the amount of oil in place as the A and the B. So we're focused on the A and the B. We'll eventually drill D wells. As you move east, where you're discussing, the people are completing D wells. The A and B goes down significantly based on our data points. And so they only have the Wolfcamp D to go after, and they're making, looks like, some pretty good wells. So we'll eventually drill some D wells, but right now the A and B has so much more oil in place, and that's why we're focused on the A and the B.

Timothy L. Dove

Now you'll recall, Sven, we drilled a D zone well at Cline well effectively in Midland County a couple of years ago now, it seems like. And the well seemed to be a disappointment. It made 250 barrels a day on a very small lateral, about 40,000-foot lateral. So you look back on that, we've somewhat proved up to be in Midland County just by virtue of that well. Now then we'd have to come back and drill longer laterals and prove it up from the current style of completions, but that's definitely encouraging.

Sven Del Pozzo - IHS Herold, Inc

Okay. And just finally, I can even send an email for this one, but were there any sales proceeds in the third quarter that came through?

Richard P. Dealy

Yes, we had -- in our unusual items, we had the closure of the South Africa transaction. And we closed on a small piece of land in Alaska that we called in our unusual items.

Sven Del Pozzo - IHS Herold, Inc

Can you give me a rough estimate of what the net sales proceeds were from that?

Richard P. Dealy

Yes. The net cash for South Africa was around $16 million after the -- we'd gotten the cash flow for the most part of the year. And on the Alaska one, it's around $10 million.

Operator

And we go next to Gordon Douthat from Wells Fargo.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Just a couple of questions from me. First, as you ramp up horizontal drilling, to what extent do you have 3-D seismic coverage across your acreage?

Timothy L. Dove

Well, we're shooting 3-D, as we speak, in the south still. We'd probably have that done early next year and have most of the area covered. A lot of areas to the north we already have 3-D.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. And then one last question for me. You kind of hinted at this early in one of your responses earlier, but just want to make sure. As you get down to 25 rigs in the Spraberry, the vertical rigs, and looking at your location count in that play with 4,700 PUDs booked, how do you think about those PUDs with the 5-year rule, recognizing that you're also picking up some of the deeper zones now and you're drilling a lot bigger wells with the horizontal wells? How do you think about all those factors as we look into reserves coming -- head into year end?

Scott D. Sheffield

E

Yes, we'll just have to, over the next 5 years, manage the ones we are adding deeper rights in several key areas on the vertical program. So that allows us, by adding those zones, to -- if we do lose them, we can rebook them at some point in time, if you add deep rights as we co-mingle with the deeper zones such as the Strawn, Atoka. So we're doing some of that. And if we lose any because of the 5-year rule, then we just got to replace them with all the horizontal wells that we're drilling which has a much, much bigger impact.

Timothy L. Dove

The way I would look at that also is, I mean, these reserves we're talking about here are essentially 0 risk, and they're essentially proved technically. So the 5-year rule really has nothing to do with how proved the wells will be. They are already proved technically. So that's just another insight, I think.

Gordon Douthat - Wells Fargo Securities, LLC, Research Division

Okay. And then as far as the deep rights go, is it your intent to cover your -- to scoop up all those where you don't have them?

Scott D. Sheffield

We've gone -- from the last 3 to 5 years, we've gone from 50% up to about 80%. And so we like to try to get it higher and higher, the entire position.

Operator

And, ladies and gentlemen, due to time constraints, this will conclude our question-and-answer session. Mr. Sheffield, I will now turn the conference back over to you for any closing remarks.

Scott D. Sheffield

Again thanks for all the interest. We're looking forward to the next quarter. We hope everybody has a great holiday. And again, our hearts and prayers are for the ones up in the Northeast. Hope all goes well with you and your families. Again, thank you very much.

Operator

And again, ladies and gentlemen, this will conclude today's conference. Thank you for your participation.

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