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Pioneer Natural Resources (NYSE:PXD)

Q1 2013 Earnings Call

May 02, 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 and Chief Operating Officer

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

Analysts

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

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

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Brian Singer - Goldman Sachs Group Inc., Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Mario Barraza - Tuohy Brothers Investment Research, Inc.

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

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

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Operator

Welcome to Pioneer Natural Resources' First 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 Webcasts. This call is being recorded, and a replay of the call will be archived on the Internet site through May 27.

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'm going to briefly go through the agenda for today's call. Scott will be up first. He's going to provide the financial and operating highlights for the first quarter of 2013, another solid quarter for Pioneer. He'll then review our capital program for 2013 and our production growth outlook for the 2013 through 2015 period. This will be followed by some perspective on how big the horizontal Spraberry/Wolfcamp shale play can become for both industry and Pioneer over the next several years.

After Scott concludes his remarks, Tim's going to discuss our horizontal drilling programs in the Spraberry/Wolfcamp, both in the southern Wolfcamp joint interest area and across Pioneer's extensive northern Wolfcamp/Spraberry acreage position. He'll then update you on our Spraberry Vertical, Eagle Ford Shale, Barnett Shale Combo and Alaska operations. Rich will then cover the first quarter financials in more detail and provide guidance for the second quarter. And after that, we're going to open up the call for your questions.

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

Scott D. Sheffield

Thank you, Frank. Good morning. On Slide #3, Pioneer had another great quarter with adjusted income in first quarter of $136 million or $1.02 per diluted share. Our first quarter production, 171,000 barrels of oil equivalent per day was above our guidance range of 165,000 to 170,000. That's up 6,000 barrels a day or 4% from the last quarter. That's primarily being driven by our Spraberry Vertical program, that's taking wells all the way down to the Atoka and the Mississippian in addition to the horizontal Wolfcamp Shale and Eagle Ford Shale drilling programs.

We're continuing to have great results from our southern Wolfcamp joint interest area. We did place 9 new Wolfcamp B wells on production with an average peak 24-hour IP rate of over 900 barrels of oil equivalent per day. Oil content was 82% oil. We did pump slickwater fracs on 5 wells through April, saving up to $1 million per well as compared to hybrid fracs, with results very encouraging either as good or better than the gelled fracs. We are nearing completion. We expect early June, waiting on the final regulatory body in China for the Sinochem joint interest transaction to close.

A quick update on our northern horizontal drilling program, which has been underway. We did recently fracture our Martin County well, and that well will be put on flowback in the next couple of weeks. We're adding 4 additional rigs to that rig during the second quarter. We did pick up a fifth rig, and that's going to be focused on the Hutt area where our well came on over -- about 1,700 barrels a day. So we'll have that fifth rig essentially focused on development drilling in the Hutt area. So we'll have a total of 5 rigs running by the end of the second quarter through the remainder of the year, going on up to 8 rigs going into 2014. Two of those rigs will be focused on Jo Mill and Spraberry Shales, which they'll be spudding soon.

Going to Slide #4. Again, we're continuing to see significant incremental production from our deeper vertical drilling in the Spraberry, with our 15 rigs primarily taking wells down to the Strawn and through the Atoka and the Mississippian. Eagle Ford continued to overperform with 37,000 barrels of oil equivalent per day, representing a 7% growth from the fourth quarter. We had a very successful winter drilling program in Alaska. We fractured our 4 horizontal wells, 3 in the Nuiqsut and 1 in the Torok. Two of those wells have recently come on with peak gross production rates to date, they're still climbing, of 3,500 barrels a day and 3,000 barrels of oil per day. In addition, our appraisal well, definitely, in looking at the results of that well, allowed us to increase the original 50 million barrel discovery onshore to somewhere between 75 million and 100 million barrels. And again, we added -- with the run-up in gas prices, we added gas derivatives from '13 through 2016.

Going to our CapEx spending on Slide #5 and cash flow. Nothing has changed here. Important point, with adding the fifth rig, we are not changing our CapEx for the year. We had a -- we had built in a -- we had not built in a delay. The additional rigs were supposed to start up a little bit earlier in the northern appraisal program than they actually did. So it allowed us to pick up the fifth rig and start the drilling on the Hutt area without increasing CapEx. Also, we had -- our first quarter was front-end loaded with -- there's probably over $100 million in the first quarter with Alaska, drilling being primarily front-end loaded. And, secondly, the -- our transaction with Sinochem, we're picking up 100% of the costs even though it will be reimbursed at closing, 40% of the capital costs, but it's not credit to costs incurred. So we're obviously on track for the rest of the year, drilling capital of $2.75 billion, capital program of about $3 billion, funded with operating cash flow, cash on hand and the joint interest cash proceeds expected in early June.

Going to Slide #6. Again, with our quarter announcement of 171,000 and above, our guidance, we're still on track to deliver 175,000 to 181,000 barrels of oil equivalent per day. Our liquids is moving up a little bit faster. We're up to 63% liquids, first quarter. Obviously, we're excited about that. The low end of this range assumes $85 oil, flat; $3.25 gas. The higher end of the 18% CAGR is more towards a $100 oil and $4.25 gas. Again, to remind people, we are not modeling in this growth rate the Hutt type performance, which is closer to a 1 million barrels of oil equivalent. We're modeling essentially 500,000 barrel ultimate reserves in this growth model.

Slide #8. Just a few key slides to show you how big this Wolfcamp/Spraberry Shale play is. On Slide #7, this is a map we came out with about 3 to 4 weeks ago that -- this is strictly the Wolfcamp B. It's probably going to be your biggest driver and your biggest resource potential. We've come up with 22 billion barrels of oil equivalent. The key point here is our geoscientist. Based on 70,000 logs, based on 1,400 square miles of 3D, 4,000 feet of core. And in addition, we have tested selectively the Wolfcamp zones over the last several years from vertical fracs. And what's interesting from the -- where EOG in approach in the very southeastern part of the map, we draw a line up to our Giddings, then up to our Hutt well in Midland County, then all the way over to a third-party well, you're looking at about 100 miles. So we only got about 50 miles to go to prove at this play to the north. So 2/3 of this play has already been proved up. We're assigning 22 billion barrels of oil equivalent resource potential. That's on a 140-acre spacing. We're already starting to move toward 70-acre spacing in our southern JV area. So you see, just the Wolfcamp B will probably end up being the biggest discovery in North America.

Going to the next slide on Slide #8. We have assigned reserves and risked it for the Wolfcamp D or the Cline, the Jo Mill and the Wolfcamp A. Again, only a 140-acre spacing. Almost all your shale plays discovery to-date are going either down to 70-acre spacing or even as low as 35- to 40-acre spacing. So again, tremendous potential in all these various zones, which will all be tested over the next 2 years.

Slide #9. Just to rank it in regard to where it sits with other U.S. oil fields. Before the shale era, Prudhoe Bay, was your largest discovery at about 13 billion barrels recoverable. Obviously, the Bakken is around 12 to 13 billion barrels. Eagle Ford is around 26 billion barrels. The Delaware Basin, over time, will come up significantly, as people put together their own maps. But the Spraberry/Wolfcamp in the Midland Basin, obviously, is the big driver. And there's probably a lot of upside from here, obviously, with -- we are not adding the 2 lower and middle Spraberry shales, which we'll be testing. And again, this is on a 140-acre spacing.

When you look at Slide #10, what's the potential this could do for the U.S., you can see that, over the next 20 years from 2013, we're starting at a 0 point even though there is significant production already from this field of about 450,000 barrels of oil per day. There's 264 rigs drilling in this area already, both vertical and horizontal drilling is at -- and it's going to end up growing up to about 2.5 million barrels a day equivalent, with Pioneer's share being about 30% of that and getting up to 750,000 barrels of oil per day equivalent. It's made up of about 70% to 75% oil. Even though most of our wells are coming on about 80% oil, over time, over the 30-year life, 40-year life of these wells, they'll end up producing about 70% to 75% oil. And this has taken the rig count up to about 170 rigs, with Pioneer contributing about 50 of those rigs -- of the 170 rigs.

Let me let Tim talk to you about the growth in our assets.

Timothy L. Dove

Thanks, Scott. As his last couple of slides show, we have some very fortuitous [ph] goals for Pioneer in the Permian Basin for the next few years. And reaching those goals, of course, will depend upon execution. And you can see in the next several slides that I go through that we've made an excellent start in terms of doing just that.

First, I'm going to touch on, on Slide 11, the recent well results in the southern Wolfcamp joint interest area. You can see, in the blue boxes, 24-hour IP rates. On average, those were about 911 BOE per day, 82% oil. The average lateral length in those was about 7,100 feet, with the exception of that well you see at the very top, the University 10-1 #4H, which was just under 10,000 feet. But suffice it to say, with these kind of consistent results, they certainly reinforce our view that the southern acreage will deliver at or above the 575,000 BOE type curve that we've been establishing for this area in the south.

Now on Slide 12, turning to drilling activity in the south. We currently are running 7 rigs. We continue to focus on a expansion of the rig count up to 13. That will take our well count from about 86 wells this year to doubling that roughly 165 wells in 2015. So we've got a very significant acceleration built into the plan.

2013, of course, is the first year in which we're working on delineating acreage. We're testing several different intervals. We have the well cost estimate now ranging from $7.5 million to $8 million. Now that's based on 8,300-foot lateral, which is the average we anticipate for this year. That, however, excludes the benefits of pumping slickwater, which I'll talk about in just a minute.

Also, an important component of this campaign is to drill more 10,000-foot roughly laterals. We plan to drill over 20 of them this year. And our early data suggest that a 20% increase in costs that comes from the extension of the laterals is actually incrementing EURs perhaps up to 60%. So we really see a dramatic increase in efficiencies coming out of extending laterals. So we'll do that wherever we can, wherever the leasehold allows us to do it. Also, we're going to be seeing efficiencies coming out of the fact we're increasing our use of pad drilling, about 70% pad drilling in 2013. Scott's already alluded to our downspacing opportunities. Right now, we're testing 100-acre spacing. But as he mentioned, it's very possible we will go lower in the fullness of time to perhaps even down to 40-acre spacing or so.

Now to the slickwater fracs, we pumped 5. This can save $1 million dollars a well if you count all-in costs, including reduction of resin-coated sand requirements and so on compared to gel hybrid frac that we -- have been the basis of our earlier drilling. The 2014 campaign in the south will be more of the same, I would say, development drilling, increasing production even with a higher percentage of pad drilling. So in summary, we're certainly hitting our stride in the southern drilling campaign and expect to continue to do so.

On Slide 13, moving to the northern acreage. We'll be drilling 30 to 40 wells in the north, split between various Wolfcamp zones as shown on the slide and various Spraberry Shale and the Jo Mill zones, shown on the right-hand side of the slide. In essence, what we're doing in this case is delineating these various prospective intervals with the idea of proving up acreage. In various of these cases, we have over 600,000 acres per zone. So it adds up pretty quickly in terms of the prospectivity. As Scott has already mentioned, we're moving from 1 rig in the first quarter in the north to 5 here by the end of the second quarter. I'll give you a little more granularity on that on the next slide. The well costs here in the north, we anticipate to be slightly higher, $7.5 million to $8.5 million, for a 7,000-foot lateral. Again, it's under the basis that if you go -- as you go to the north, you're also doing deeper drilling and the deeper drilling has additional costs. Those numbers, however, do not include any benefit what would come out in pumping slickwater.

Now to Slide 14 and focusing on the second quarter drilling in the north. We'll be following up the DL Hutt well with further drilling in that area. And particularly, what we're doing is bringing on the second well that was drilled alongside that first Wolfcamp B well, bringing it on production here shortly. You may recall, we wanted to make sure we established a good, long-term production test for the B interval well before having to shut it in because we do have to shut it in, as we do the A completion in the offset well. And so, accordingly, we'll be very surely up there in the Wolfcamp A well doing a fracture stimulation and putting it on production. At that time, we will have to shut in the DL Hutt C #1H.

As it relates to the Martin County drilling, Scott already alluded to the fact that we have drilled and now completed the Martin County well. We're just drilling out the plugs, as we speak, and should be on production, as he said, next week or the week after. So we'll have some imminent production data on that.

We are adding 4 horizontal rigs. As he said, 3 were planned in our original planning. We've decided to add 1 additional rig to focus on developing the Hutt lease, where we made such an outstanding well, the best well in the play so far.

Capital will be essentially flat, from the standpoint of drilling, $2.75 billion from our original plan. We can absorb the incremental rig, as he mentioned, mostly because some of the additional rigs were coming in a little later than anticipated and the 5-rig program will consist of 3 rigs focused on Wolfcamp zones and 2 on the Jo Mill and Spraberry zones. We will be drilling most of these wells on 2-well pads to gain efficiencies, and the wells will only be completed after the second well is drilled on each pad. What that points to is the need to be patient and waiting for well results as the year goes on because it will be quite a long timeframe between when the first well is spudded and the first and second well are put on production.

Now turning to Slide 15. As for the type curves, our key wells are still performing beautifully. If you look at the DL Hutt well, it's shown on the blue on the graph, it's now made about 100,000 BOE in just over 100 days. So needless to say, a phenomenal well. Our Jo Mill well, shown in the orange color, are doing well also for a seasonably relatively short laterals. When these are normalized to 5,000 feet, you can see they're exceeding the 650,000 BOE type curve, which is the dash line on the graph. And our Giddings wells, of course, these are now some quite a long time in production, almost 1.5 years, but they're substantially over the 650,000 type curve even though they're only about 5,300-foot laterals. What you can see in the graph, if you look there between days 240 and 270 is a substantial benefit from putting these wells after -- or on artificial lift. You may recall, most of these wells -- these 2 wells were flowed naturally before that, and you can see the benefit of artificial lift. So needless to say, we're very pleased with these results and think they bode very well for our future drilling success in both the north and the south.

Then finally, on Slide 16, looking at the next 2 years of the horizontal campaign in the north. Really, what we're doing here is connecting the dots, as you can see on the map, in various zones. And the objective here is, across the 6 stacked laterals, to prove up this acreage, which we think, in the Wolfcamp and Jo Mill intervals, including the Spraberry acreage, to be some 3 billion BOE of potential reserves and potential resource. Production is increasing. Of course, expect that 2013 horizontal production will be 5,000 to 7,000 barrels a day. And at that point in time, as we get through the end of 2013, we'll be moving more up to about 8 rigs. So the idea is to use about $1 billion in 2013 and '14, so $400 million in 2013, $600 million in 2014, to continually -- to continue the appraisal program to test spacing optimization, just as we're doing in the south, and essentially learn what it is these various zones can deliver, so that we can then optimize our capital budget and our capital drilling campaigns in 2015 and beyond.

Turning to Slide 17. Of course, with all the excitements surrounding the horizontal campaign, it should be emphasized that the Spraberry vertical drilling program is still doing exceedingly well, especially based on the fact that we're drilling these wells in the case of 90% of the entire program to deeper intervals. So this is still a major contributor to our Permian performance. We are still operating 15 vertical rigs. They are required essentially such that we can meet continuous drilling obligations and preserve our leasehold for further incremental horizontal drilling on the same leasehold. And we drilled about 75 vertical wells in the first quarter or so, right on target with about 300 for the year. We did place 130 wells on production. We did decrease our frac bank by about 55 vertical wells in the first quarter. You may recall that we delayed some of the completions in the fourth quarter of 2012 so that we would match up our spending more closely with our cash flow in that year, as the horizontal campaign was being accelerated. But needless to say, these deeper zones, as shown on the table, had significant EUR and cover a substantial amount of our acreage.

And then, Slide 18 shows that, eventually, all of this activity finds its way to production. Excellent first quarter, up about 10% in terms of production of about 75,000 BOE. We did benefit from the frac bank reduction I just mentioned. But at the same time, we were hurt by the fact that we had about 2,700 barrels a day of ethane recoveries, which were reduced, as a result of having a full production and actually exceeded capacity in our Spraberry gas processing facilities. That's now essentially been alleviated. The 200 million cubic feet a day plant at Driver has now come online during the mid part of the last month, and we're in the process of alleviating that ethane recovery issue, as we speak, as we continue to add gas into that system. Overall horizontal production is expected to increase from only about 2,000 barrels a day last year to 11,000 to 14,000 barrels a day this year. And of course, that includes the fact that we will be conveying production to Sinochem at the -- after the closing of that transaction.

Turning to Slide 19 and specifically talking about Eagle Ford. The Eagle Ford team had a phenomenal quarter and continues to set production records in that asset, 37,000 BOE, up about 12% from the fourth quarter. They're very much on target to drill their campaign. They've drilled 37 wells, 35 having been put on production, and anticipate drilling about 130 wells this year. Those are effectively almost 100% all liquids-rich wells. We're minimizing any sort of dry gas drilling, as we speak. The economics on the oil and condensate drillings is so much better than natural gas drilling even with an increase in natural gas prices. And we're also substantially increasing pad drilling to about 80% of the program. It saves about $600,000 to $700,000 per well. And one of the results of that is we can drill, because of the efficiencies of pad drilling, the same number of wells with less rigs. This year, we used 10 rigs to drill 130 wells, where it took 12 last year.

Just as we're doing in the Wolfcamp, we are evaluating downspacing. We are testing, as we speak, 70- to 80-acre spacing in our oily areas of the Eagle Ford and perhaps into some of the liquids-rich areas, and then perhaps even down to 40 acres in some areas. So we'll be giving you more information, as those results are seen.

We're continuing to push the envelope with the use of white sand as opposed to ceramic proppant. It's now anticipated that 70% of our program will use white sand, which reduces the cost of the fracs by some $700,000. So that's a very important thing to continue to push with regard to the technology of the use of white sand as deep as we can do so. We're effectively completed with most of our central gas processing facilities. We'll add one more next year. So in summary, Eagle Ford is hitting on all cylinders, and we expect this level of performance to continue into the future.

On Slide 20. In the Barnett Shale Combo Play, we've added a second rig. You can see production is about 9,000 barrels a day. We anticipate that to increase, as we put this rig to work. We have about 20,000 acres held by production. There's about a 40,000 acres or so that we -- of our total 60,000 additional acreage that we believe are prospective and in more liquids-rich drilling, and that will be the basis of a 2-rig campaign over the next 3 years to make sure we can preserve that leasehold.

The team has done an outstanding job in terms of reducing well costs. In fact, they recently drilled wells in less than 8 days, bringing the well costs in under $3 million for a 5,000-foot lateral. And accordingly, our economics have improved quite substantially, considering our well costs have come down at the same time we've seen improvements in natural gas prices.

Turning to Slide 21, Alaska. Scott already alluded to some of the results here, but I'll give you a little bit more granularity. Our winter campaign is essentially complete, and we're just right now in the process of evaluating the results in the form of how these wells are going to produce. First quarter production was about 4,000 barrels a day. You may recall that, on the island, we drilled a very successful Nuiqsut well in 2012 and put a diverted -- mechanically diverted frac on that well. It has now made 685,000 barrels in 1 year, so it's a phenomenal well. So that led us to then drill 4 more wells from the island that we would frac this winter. Those fracs have now been done. Two of the wells are on production. Scott gave you the rates on those, about 3,500 and 3,000 barrels a day and still unloading. So we'll see eventually where they IP. The 2 additional wells we anticipate bringing on production this month. So we'll be able to give you more information on that, as we get the wells on production and they unload. We will have a little bit of downtime in the second quarter, as our third-party processing partner will be having some downtime. It'll be about a 10-day to 2-week window in the second half of June, in which we'll be shut in, but we already have that factored into our guidance.

The Torok well to the south is very interesting. We had originally drilled the first of the Torok tests in 2012. That well came in exceedingly well. And in fact, we went back in and retested that well this first quarter. And it produced at about 2,800 barrels a day on a gross basis even with facility limitations that tend to occur on the north slope. But that's substantially better than the tests even we had last year when we were even more facility-constrained. The well we just drilled this winter looks excellent. The logs look quite excellent in the Torok. In fact, they confirm really high-quality reservoir rock. And we had planned to production test that well. But after moving the rig off location and rigging up for the completion, we found we had a mechanical problem in the well that would require remobilization of the rig. But it was too late to remobilize a rig based on the winter season and the ice needs -- and the ice conditions to do so, such that we had to suspend operations. But logs from the well look excellent and give us confidence to be able to increase the resource potential from this Torok zone to about 75 million to 100 million barrels from about 50 million.

So with that, I'm going to pass it over to Rich for his review of the financials and guidance for the second quarter.

Richard P. Dealy

Thanks, Tim. Let's start on Slide 22. For the quarter, net income was $101 million or $0.75 per diluted share. It didn't include mark-to-market derivative losses of $60 million or $0.45 and unusual items of income totaling $25 million or $0.18 per diluted share. So as Scott mentioned, after adjusting for the mark-to-market losses and the unusual items, we're at $136 million or $1.02 per diluted share.

Looking at the bottom of this slide where we showed -- or put out our first quarter guidance, and you can see our results. If you look at that, we were in guidance -- on the positive side of guidance in all those items. I won't go through those in detail, but an excellent quarter as both Scott and Tim have mentioned.

Looking at Slide 23, on price realizations. You can see, on oil, we are up 6% versus the fourth quarter to $88.57. If you look at NGLs and gas, both those were down slightly compared to the fourth quarter. Given what the recent run-up in gas prices, we'd expect the second quarter to be better, NGLs probably more of the same what we've seen in the last 2 or 3 quarters.

At the bottom of the slide, you can see the positive impact that's incremental to these prices from our derivative portfolio. That's included in derivative gains and losses on the income statement.

Turning to Slide 24. Production costs came in at $14.52 for the quarter. They're essentially flat with the fourth quarter. So things are going as expected there, and would expect the same as we move to the second quarter.

Turning to Slide 25. In the company's liquidity position and financial position, very strong financial position with $2.4 billion of net debt, excluding the MLP debt. Great liquidity position with $430 million of cash on the balance sheet, completely undrawn $1.5 billion credit facility out there, so in good shape financially. One thing, for those that may have missed it, we did call for redemption, the remaining about $200 million of convertible bonds that were outstanding. That will be completed in mid-May. And after that is completed, we would expect our outstanding shares to be about 138 million to 139 million shares.

Turning to Slide 26 and second quarter guidance. As Scott and Tim both talked about production, well, it's continuing to increase in the second quarter. We're projecting 174,000 to 179,000 BOEs per day, primarily driven by Spraberry/Wolfcamp, Eagle Ford, Alaska. The rest of the items on this page are similar to what they've been in past quarters. So I'm not going to go through each one of those in detail, but they're there for your review. At this point, we'll go ahead and open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] We'll go first to Doug Leggate with Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple of fairly high-level questions. If I look on Slide 16, your -- I think you cannot talk about -- this is joining the dots, I guess. But as I recollect, all this acreage to the north has long been held by production. So why such a diverse appraisal program as opposed to a more concentrated development program in what clearly looks like a phenomenal bunch of acreage that's already held?

Scott D. Sheffield

Yes. Doug, as you can see, on that Slide 16, our northern appraisal program, we're testing the larger blocks that we hold. So you can see where the yellow comes together. These were where we have some of our biggest acreage blocks. We think it's important to prove up. Obviously, the Wolfcamp B, we're very confident of that, and then eventually start looking at the Cline or the Wolfcamp D. And then, we'll be testing 3 Spraberry shale intervals. So these are all where our biggest blocks are, and that's the focus. But if we see tremendous results like on the well we did in Midland County, the Hutt well, obviously, we'll be refocusing rigs there over the next 2 years on the better areas. So the goal is to prove up our acreage even though 80% of it is held by production. There's only about 20% that's not. But it's really to cover our big acreage positions going all the way up to the north.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Great. [indiscernible] So I guess we should expect that once you've gone through this, you'll concentrate the rigs back in what you see as the best areas. Is that a fair assessment?

Scott D. Sheffield

Exactly, yes.

Timothy L. Dove

And I'd say best areas in best zones, right?

Scott D. Sheffield

Yes, both.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Right, right. So I guess my follow-up, if I may take another one, is, Tim, on the lateral lands, obviously, there's been a lot of normalizing to longer lands. What is the limitation on drilling? I guess, if we could maybe segregate it [indiscernible] the northern acreage, what is the limitation that you're going for the longer laterals? Is it just the connectivity of the blocks, or because you've got this pretty well blocked up?

Timothy L. Dove

Yes, very clearly. The only limitation, let's say, when you're going from 7,000 to 10,000 feet is the leasehold position, and do you have the contiguous leasehold in position, such that you can cross leasehold and be able to get out to the 10,000-foot level? Of course, in a lot of areas, what we're trying to do is work deals where we can either acquire or work with the offset leases that we don't own to make sure we can drill the longer laterals. So I think what was going to happen is, through time, you'll see us further moving towards longer laterals, where we can do so.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. And the final one, Scott, I guess, this one will be for you. I know I've asked you this before, but I'm going to try it again. An enormous resource clearly. And if the multiple zones work, what is the longer-term plan as to how you pursue optimal development?

Scott D. Sheffield

Yes. Doug, I think the -- obviously, with our production growth CAGR of 13% to 18%, we're still using a 500,000 barrel type curve to generate that. And so, I think the key is if we can make wells more like the Giddings, say, 700,000, 750,000 or up to the Hutt type wells, 1 million barrels of oil equivalent, then we'll be -- our wells that pay out in 5 months -- the Hutt looks like it may pay out in about a 5- to 6-month timeframe. If we can make those type wells, we'll be generating enough production growth and cash flow to be able to take this company forward for the next several years and substantial double -- to high-double digit production growth rates. So we really don't need funding sources if we make those type wells.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

But in terms of optimizing value, Scott, would there be a route to perhaps monetizing part of this, or is that off the table?

Scott D. Sheffield

No, we're not even considering it right now. So we're putting any decisions off until we get an idea of what these 3 Spraberry shale zones are going to do and what the B and the D zones are going to do over the next 2 years. We'll be making that decision by, say, the end of '14.

Operator

Our next question comes from Charles Meade with Johnson Rice.

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

I actually had 2. Let me just to start off with. Can you talk about -- or could you tell us how big the Hutt lease is? And really, what I'm after is, is with the rig that's going to be dedicated there, is this going to be drilling a dense spacing pilot, or is this going to -- is this a significantly sized lease that's going to be spread around?

Scott D. Sheffield

Yes. We've picked up really 2 or 3 Hutt leases over the last 20 years from some major oil companies. And so, it's a huge lease. One thing interesting that we don't comment on is that it's 93% net revenue. So there's only a 7% royalty on a lot of these leases. And so, that's another reason why we're focused on that -- on those areas also. So it's a huge area, a lot of it development drilling and very high net revenue interest.

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

Got it. And then, the second question I had, it goes back -- I think Doug may have touched on this in his earlier question. With the normalizing of the well curves for the Jo Mill, is that just a scale or multiple based on lateral length that you do to normalize those curves up?

Timothy L. Dove

Yes, Charles. Of course there's a lot of data in shale plays that support the idea that you have quite a strong correlation between lateral length and productivity. In this case, we haven't drilled a 5,000-foot lateral. The couple of wells we drilled are 2,500. But we believe that you'll get a linear effect -- or a linear multiple -- or scaler multiple effectively by doubling the lateral length. And so, we'll, of course, be reporting more as the next wells we drill in Jo Mill will in fact be 5,000-foot lateral. So we'll be able to tell you more definitively once those wells are done. But we think, conceptually, it still points to the direction that the wells are performing at pretty solid rates.

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

Got it. And this would just be the last follow-up, but is it going too far then, because when I looked at your slide, I believe at Slide 13 that has those well curves on it -- actually it's 15. You have the Hutt, which is 7,400-foot lateral against those Jo Mill at 5,000. If you just bumped up the Jo Mill by another 50%, that would seem to imply that the Jo Mill could be your best zone in this -- in the column.

Timothy L. Dove

It could easily be the case, Charles. If you think about the Jo Mill and the Spraberry shales in connection with those if they have excellent well performance similar to the Jo Mill. They also can be drilled cheaper than Wolfcamp wells, probably $1 million, $1.5 million less. And so, there's a double benefit if, in fact, they produce at this level. But you have to sort of tap the brake a little bit. We need to get some longer lateral Jo Mill wells drilled. We need to get these Spraberry shale wells drilled. And we'll know more in the fullness of time how they're going to produce.

Operator

Our next question comes from Gil Yang with DISCERN.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

You've had some great results in Alaska. Can you talk about what you need to see to narrow that 75 -- that range of 75 to 100 million barrels further? And when I look at the map in terms of where those wells were drilled in the overall shaded area, how many more sort of parcels could you de-risk through appraisals? And I have a follow-up on that.

Scott D. Sheffield

Over the next 3 months, our Alaska team is going through the evaluation for the next winter program and in addition on whether or not we'll be sanctioning this project moving forward. And so, we'll know more information. But right now, we feel very good about these first 2 wells, Gil, in addition to the fact that we've drilled -- we have 2 other wells that are very successful on the island. So the team is working up that project right now with the recent change in the Alaska tax laws that looks very positive, again, for this project also going forward.

Timothy L. Dove

And just 1 additional note in that, Gil, and that is that we have 3D seismic in this area, and the wells -- well results very well correlate with that 3D. So it gives us a lot of confidence moving forward in those numbers that you mentioned.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Are there many additional, sort of, parcels that you can de-risk and add sort of 25 million, 50 million barrel increments? Or have you sort of fully de-risked that shaded area -- or into the resource potential category?

Timothy L. Dove

Yes. Potentially to the south, we could add some resource potential because we -- these wells that you can see were drilled off the land heading a little bit to the northwest. But suffice it to say, we think we're getting in that range, 75 to 100 million barrels, based on the data we have.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Okay. And what is the -- what are the results in the new tax laws you -- make you think about in terms of how to best capture the value for this asset? Is it to produce it or to sell it down the road?

Scott D. Sheffield

They have substantially reduced the taxes on producing properties going forward. That's the big benefit.

Gilbert K. Yang - DISCERN Investment Analytics, Inc

Right. But do you -- or does it make you think about selling this, or do you think the best thing to do is to produce it out as part of Pioneer?

Scott D. Sheffield

Right now, we are evaluating the entire project. And so, we'll be making those decisions over the next several months.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I wanted to just go back to some of the comments that you made earlier on in your opening with regards to 70-acre spacing. I think you mentioned that you are testing -- or you think you can head down a 70-acre spacing in the south. Can you just add some more clarity on your views there and to what extent that is based on tests that you've done, results that you've seen from others or just where you're seeing other plays?

Timothy L. Dove

Yes. We have 3 wells right now that we're testing on 100-acre spacing. So we're clear on that, in the south. We have plans to potentially reduce that further to 70, and then perhaps even less than that. So it's early stages, Brian, but we're sort of taking baby steps. We're heading down from the more of the 140 to now 100, and we'll be further testing from there. It's important though that we get our arms around spacing because we want to do it as early as possible in the development campaign. We want to make sure that, as we go forward, we land on what's optimal spacing per zone, so that we can then optimally develop. So this is something you're going to see more information from us regarding, let's just say, the downspacing in this year and next year's campaign. We really need that as data points as we develop the 2015 onward plan.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then, you highlighted a few different reasons for the stronger-than-expected -- stronger-than-guidance production during the quarter. Can you add a little bit more granularity? Was this based on better vertical well performance because you got better and greater contributions than expected from the deeper zones? Was it just based on timing of when wells came on? Or was it more horizontal driven?

Scott D. Sheffield

It's still -- you saw where Eagle Ford way overperformed up substantially. And when you look at the Permian, it's a combination of the Wolfcamp horizontal plus bringing on several wells that are combined with the Spraberry, D and Wolfcamp and all the way down to the Strawn and the Atoka. So it's really a combination of both. And obviously, we did reduce our frac bank on the vertical program also.

Operator

Our next question will come from Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Quick thoughts here. Guys, seeing a positive rate of chain story in terms of your southern Wolfcamp wells, you noted that the last 9 wells were at an IP rate of 911 BOEs per day. Tim, this -- or, Scott, this compared to the prior 21 wells at 674 BOEs per day, yet you kept your type curve flat. So a couple of questions. One, what is driving this improved well performance? And I'm just being conservative on the type curve because the well results did get better in the south.

Scott D. Sheffield

It's a combination of longer laterals and also refocusing more of our sweet spots among the 200,000 acres. It's a combination of both.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. And just being conservative on the type curve. Is that fair?

Scott D. Sheffield

Yes.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. All right. And just second question. As you shift to putting a couple of rigs towards the Jo Mill and Spraberry, Tim, I was wondering if you could just comment on the thickness of the section -- of each of those sections compared to the Wolfcamp, which I believe, at some cases, can be up to 800-foot thick? And just comment a little bit around that.

Timothy L. Dove

Yes. Well, first of all, if you're talking about Wolfcamp, Wolfcamp is 2,000 to 2,500 feet thick. It depends on where you are. What you're referring to in the sense of the thickness...

Arun Jayaram - Crédit Suisse AG, Research Division

The B.

Timothy L. Dove

Of Wolfcamp is really the Wolfcamp B, which, especially in the south, is something like 800-feet thick. You actually can see this pretty clearly on Slide 13 that I had already gone through. And so, going through these shales, you can see that --. Well, first of all, talking about Jo Mill, Jo Mill is really about a 30-foot general -- a 30-foot interval. Basically, it's a silty, sandy zone. So clearly, from a micro seismic standpoint, it -- we can determine that the fracs in the first 2 Jo Mills were actually going up into the Jo Mill shale, as shown there on Slide 13. And so, that's where we're getting the contributions. The Jo Mill in and of itself could never produce as well as these wells have, given it's only a 30-foot interval. So we're clearly seeing shale contributions. But you can see on there that if you look at the Wolfcamp -- I'm sorry, if you look at the Jo Mill shale, which sits above the Jo Mill, it's probably in the neighborhood of 800 feet or so itself, and the lower Spraberry shale, maybe more like a 1,000 feet. So you have a substantial potential considering the size of these shales.

Arun Jayaram - Crédit Suisse AG, Research Division

That's great. And my last question maybe for Frank is, you guys have a full year target of 86 wells in the south and up north, 30 to 40. You did 9 wells up in the south in the first quarter and 1 in the north. Frank, how do you expect the cadence to proceed as you get your rigs in terms of completion through the rest of the year?

Frank E. Hopkins

Well, I think what's happened is we just ramped up to 7, I'm talking about the south now, at the beginning of the year. And so, we were just kicking off the 7-rig program we had been at 4. So I think what you'll see is that, as we go forward, you're going to get a lot more wells now with 7 rigs. And that 86 target, in our opinion, at this point, is pretty achievable. No issues there. And in the north, the north kind of reminds me of the south from last year where we started out with 1 rig, and then we got up to 4 rigs in the second half of the year. And basically, I think we drilled around 30 wells -- 30, 35 wells last year in south. And so, what you're going to see in the north is something very similar where we're ramping up here in the second quarter. And by the time we get to the second half of the year, you're going to see an acceleration, not only in the number of wells, but obviously, the Street's looking for results from those wells, which we talked about this morning. So again, achieving that 30- to 40-well target, we think, is very achievable at this point in time.

Operator

Our next question comes from Mario Barraza with Tuohy Brothers.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Just can we revisit your guidance for a bit for this year and '14 and '15? You said that the current guidance excludes a Hutt type curve. But are you using the 575,000 barrel equivalent run rate for '13 through '15 right now?

Scott D. Sheffield

Yes, it ranges between 500,000 and 575,000.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay. And in this year's guidance, comparing to last quarter's presentation, you guys upped the average lateral length from 7,800 feet to 8,300 feet. When you were compiling the guidance, was that increase factored into the current numbers?

Scott D. Sheffield

No, it has not been. This was all done before then.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay. And then, if I can jump back to your spacing, what's the average lateral length you're trying for right now in the south when you're testing on 100 acres? And as you mentioned the possibility of downspacing to, say, longer term to possibly 40 acres, what type of lateral length do you think you could work there? Could actually a 10,000-foot lateral be a possibility?

Timothy L. Dove

Yes. I think the way you have to think about this is that the lateral length is sort of independent of the spacing. I mean, if you're looking at a 100-acre spacing, that's just dictating how close the wells are going to be to each other, but it has nothing to do with the lateral length. Lateral length is essentially dependent upon the lease configuration only. So we can drill stacked laterals at 40 acres just as we could if it was at 100 acres or 140 acres in the different zones.

Operator

Our next question comes from Dave Kistler with Simmons & Company.

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

Real quickly. Looking at the well costs estimates that you guys gave us, if we think of southern well costs $7.5 million to $8 million, is that pre-factoring in moving to the slickwater fracs? I'm just trying to think about, as we move to develop that, what that means and probably extend that question into the Eagle Ford as well with the savings from white sands and pad drilling and the impact to well costs there.

Timothy L. Dove

Yes. We're actually including a small amount of effects of slickwater, but not the full amount because we're not factoring in that we may use it on the vast majority of the wells. So I think there's more as running room to reduce these numbers, both in the north and the south, to the extent we go to a full slickwater frac program. And as we mentioned in the call, it's somewhere in the neighborhood of $800,000 to $1 million per well savings. So it is -- it's clearly the direction we're going. But we've just drilled a few wells and completed them with slickwater. So we want to make we're doing the right thing and the early data looks very, very good. But in most of the data you see on the well costs, both to the north and south, have very little factoring for the use of slickwater.

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

Okay. Appreciate that. And then, following on in the Eagle Ford, you're clear in your comment to say that you're not going to be pushing the drill bit aggressively on the gas side even the gas prices have gone up. Does that potentially make the gas acreage -- or gas-level acreage there a monetization candidate for you guys, especially in a better balanced gas market?

Timothy L. Dove

Oh, I don't know, Dave. We're kind of in the process of seeing where natural gas prices are going to go. Right now, we do have a substantial amount of our acreage held by production. So that's something that we can assess through time. We have about 80% of our acreage held by production. So we can assess that. As liquids-rich as we are in terms of opportunities, we're just not getting around to any amount of dry gas drilling even at $4.25 or $4.40, whatever it may be today. So that probably will just continue to be the case. I mean, we'll look at the concept you're talking about of monetization, but it's certainly not in our front burner right now.

Frank E. Hopkins

Yes. Hello, Dave. This is Frank. Just to remind you that even last year, it wasn't a big amount. But we just let some acreage -- dry gas acreage go that we decided wasn't economic to drill. So that's an opportunity -- or I shouldn't say an opportunity, but that's the -- a possible outcome for at least some dry gas acreage.

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

Okay. I appreciate that clarification. And then, one last one relative to downspacing. I know incredibly early when we think about this in the northern section, but you'd made the comment trying to get after downspacing as early as possible. How do you balance downspacing versus attacking 5, 6, 7 different intervals?

Timothy L. Dove

Well, I think the way we will do this is drill offset wells in -- on these pads where we can to prove up downspacing concepts. So in that case, you'd be actually drilling the same zones on the same pad. So we'll be doing that in some cases, so in order to address this question of downspacing. In other case, we'll be drilling multiple zones from the same pad. So we just got to learn what it is that, number one, all of these zones can yield. At the same time, we got to understand how to further appraise those in the future in terms of how they need to be downspaced. So we have to achieve both of those objectives between now and the end of 2014.

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

And I guess, just not to belabor the point, but should we be then thinking about production, kind of, being very stair step or choppy oriented because of the time related to pad drilling and actually bringing wells online as opposed to more of a smooth progression through the next, kind of, 1.5 years or so?

Timothy L. Dove

Yes, precisely, Dave. You're onto something there. What we're going to see is -- I mentioned this on the call. But if you think about pad drilling, we drill the first well, drill the second well, complete the first well, complete the second well, put them both on production. That's a pretty substantial timeline door-to-door from the spudding of the first well to putting both wells on production, and now they'll have a substantial impact when they do so. But the fact is you had a stair step effect, especially considering in the north, where we're just going to have our 5 rigs running there at the end of this month essentially. So you'll -- what you're going to see is a couple of effects. One is stair stepping in production. You're going to see a back-weighted growth trajectory, and you're going to see us only be able to talk about certain well results until the fullness of time allows us to do so. So you got to be patient with us, as we get -- we think that's the most efficient way to drill the wells, but it's not the most efficient way to get information out. But we'll do our best.

Operator

Our next question comes from Ryan Oatman with SunTrust.

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

On the Wolfcamp A, can you talk about any pre-drill expectations you have there, and how you plan to complete that well versus the Wolfcamp B?

Scott D. Sheffield

No. It's still -- the Wolfcamp A is still based on our maps as one of the highest oil in place of any of the Wolfcamp zones. We've had 2 successful wells down to the south. Just to remind people, we have a couple of our wells that went into some faults. And so, we did not get good fracs off 2 of our wells that we've drilled. This well, we are not doing anything differently than our B fracs. And so, we'll be frac-ing that here in the next few weeks and getting those results.

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

Okay. Great. And then, can you speak for your plans for the Wolfcamp B? When should we have results there?

Scott D. Sheffield

I think the D -- I think the first D well is spudding in the next, probably, 4 weeks. And so, it will take about 30 to 45 days to drill and then probably another 30 days to complete. So you're probably off about 3 months.

Timothy L. Dove

Yes. Perhaps we should make comments at the next earnings call about D zones.

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

Okay. Very good. And then, one final one for me, if I may. It sounds like you're seeing somewhat encouraging results in the south by switching to slickwater completions. One of your peers and its vertical program has applied those somewhat successfully, it would appear. What are your plans for slickwater versus gel just broad-based as you think about both the vertical and the horizontal program?

Timothy L. Dove

Well, I mean, the fact is, with the cost savings we're staring at with slickwater and with the results to-date, which is to say we're seeing similar well performance from slickwater as compared to hybrid gel-conveyed fracs, I think it's leaning -- we're leaning towards the idea that more slickwater is better. But we want to make sure we make the right decision on that. We're going to look at the data set. One of the real benefits of using gel as opposed to slickwater is we're using less water with gel. So there's an -- there's several offsetting factors as well. But needless to say, the cost savings associated with slickwater will probably rule the day. And I think that's probably the direction it goes, more slickwater versus less.

Operator

And our last question today will come from Kyle Rhodes with RBC.

Kyle Rhodes - RBC Capital Markets, LLC, Research Division

Real quick. Just wondering what your longer-term strategy for your vertical integration division is. Is that something that you guys are looking to grow in conjunction with your accelerated drilling program, or what?

Scott D. Sheffield

Right now, with the -- our CapEx, we'll be completing our expansion, most of it for the sand mine. So we don't see much there going into '14, '15. In regard to pumping services, we anticipate going out. And any future needs based on today's economics, we will probably be going to third-parties. We'll probably continue to buy a few pulling units, work-over units per year like we have been. So that's probably about it. So it will be reduced substantially. If we ever get back into a very competitive market, where prices were as high as they have been the last 2.5, 3 years, then obviously we're going to reevaluate.

Operator

And with no further questions, I would like to turn the call back over to Mr. Sheffield for any final and closing remarks.

Scott D. Sheffield

Again, thanks. We appreciate everyone participating. We know you had other potential calls during this timeframe. Hope that you consider our call the most important one. Again, we look forward to seeing everybody. Everybody have a great summer, and we'll see you on the road sometime. Thank you.

Operator

And, ladies and gentlemen, once again, that does conclude today's call. Thank you for your participation, and have a great day.

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