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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

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Will Green - Stephens Inc., Research Division

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Sven Del Pozzo - IHS Herold, Inc

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

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

Rehan Rashid - FBR Capital Markets & Co., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Pioneer Natural Resources (PXD) Q1 2012 Earnings Call May 3, 2012 10:00 AM ET

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 Investor Presentations. This call is being recorded. A replay of the call will be archived on the Internet site through May 25.

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 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 new 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 the first speaker. He'll provide the financial and operating highlights for the first quarter of 2012, another solid quarter for Pioneer. We'll then update you on the company's outlook for production growth, capital spending and cash flow growth.

After Scott concludes his remarks, Tim will discuss our drilling results and plans for the horizontal Wolfcamp Shale, Spraberry vertical program, the Eagle Ford Shale and the Barnett Shale Combo. He will also update you on our recent drilling success in Alaska. Rich will then cover the first quarter financials in more detail, and he'll provide earnings guidance for the second quarter. After that, we will open up the call for your questions.

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

Scott D. Sheffield

Thanks, Frank. Good morning. On Slide #3, on our highlights. As Frank said we had another great quarter. We had adjusted income of $153 million or $1.23 adjusted per share. On production, we were over our range on the production side first quarter at 147,000 barrels of oil equivalent per day. That's a pickup of about 10,000 barrels a day for the quarter versus the previous quarter, at a 7% increase, primarily related to our production growth in Spraberry, Eagle Ford and the Barnett Shale Combo play.

Oil represented 74% of that quarterly production increase. We're still highly encouraged by the entire play that we're seeing in the horizontal Wolfcamp play. We still feel like it will be probably the biggest oil play in the U.S. over the next several years. We're up to 4 rigs in that play. Most of our activity now is focused on the southern portion where we have university lands that's expiring over the next 18 months to 20 months.

We just brought on 2 recent wells on artificial lift: one is on jet pump and one is on gas lift. They're making mostly water at this point in time. We are still continuing to have great success by going deeper to the strong Atoka and Mississippian intervals in the Spraberry field, one of the primary reasons that we're seeing continued great success this past quarter in the Permian basin.

In the Eagle Ford, we added our ninth CGP, expect 2 additional CGPs online by mid-year. In Alaska, we had recent success with a couple key wells, one was onshore, the Torok, where we've drilled several wells on the island. We did a plug and perf technique onshore and got a 2,000 barrel a day IP rate. That well has been suspended, and we'll look at testing it longer next winter and most likely, drilling another appraisal well next winter up there in the Torok, essentially it will give us about 50 million barrel a day discovery.

And secondly, what's maybe even more important is that we did a plug and perf for the first time on the Nuiqsut. Nuiqsut is our main producing formation reserve-wise. We got a 4,000 barrel a day rate there. Tim will talk more about this later on.

We completed our acquisition of the sands business. We renamed it Premier Silica. The integration has gone tremendous. Everything is going very fine there. We added frac capacity totaling 25,000 horsepower in Spraberry during April and expect additional 45,000 by midyear for a total of 300,000 horsepower for the company.

We added some recent oil derivative positions, primarily in 2014. We'll continue to increase the percentage in the later year, 2014, on the oil side. And then, as we have mentioned before that we were close to an agreements. We have an agreement now to sell South Africa to the national oil company, PetroSA, for $52 million before tax and expect closing later this summer.

On Slide #4, production growth targets. We're still on track of hitting first quarter at 147,000 barrels a day. Our guidance, 148,000 to 153,000 for the year, on track to deliver our 23% to 27% production growth. We're still on track to deliver our 20% CAGR over the next 3 years. One note, we are already up to 58% liquids in the first quarter of 2012, moving up to 65% liquids in 2014.

Slide #5, on capital spending and cash flow. Our capital budget is going to remain the same: drilling, $2.4 billion; and about $400 million on vertical integration. We are front-end loaded on the first half of the year, primarily due to the Carmeuse acquisition of $300 million, in addition to our great efficiency in the Permian basin, with our frac bank people working 24 hours a day on several of our crews, getting our frac bank down. Obviously, we have a lots of sign-ups for the first half in a lot of our wells in the horizontal Wolfcamp play.

Operating cash flow of $2.2 billion, equity proceeds of about $500 million, inventory reduction of $100 million will be within how we plan on spending our $2.8 billion. You can use your own price deck to look at the price. Obviously, the strip is a little bit higher than our $100 price deck. Hopefully, it will come in at least that high and maybe even higher.

Slide #6. Great operating cash flow in the company, again $2.2 billion. That's based on $100 oil and $3 gas for 2012, coming on up to $2.8 billion next year for 2013 and over the next 3 years, at 25% CAGR, compounded growth rate. 80% revenue moving up to 90% revenue. I think we're estimating about 83% of our revenue be from liquids in 2012.

Slide #7, we used this slide recently at a recent conference, so we did not show it at the last quarter's call. Just an update on our resource potential on Slide #7, significant proved reserves and resource potential. The big change is primarily in the Permian basin, primarily continuing to add deeper potential for the strong Mississippian and Atoka reserves, continued to see great results from our 20-acre drilling. And then, we added 1 billion barrels of oil equivalent, 3,000 horizontal Wolfcamp locations. This is only targeting the B -- the Wolfcamp B formation. Eventually, we'll be planning both A Wolfcamp and also, C Wolfcamp and eventually, some more clients over the next 12 to 18 months. So it's a huge upside potential to the 1 billion barrels of oil equivalent potential.

Slide #8, investment highlights. With the divestiture of South Africa, we're now back to a solely 100% U.S. asset base. We have over 30,000 liquids-rich drilling locations, with over -- resource potential of over 5 billion barrels of oil equivalent. The third most active driller now, with our 2012 program, focused on 4 great plays, delivering one of the highest compounded annual production growth rate over the next 3 years and cash flow growth rate of 20% and 25%.

With first quarter results, we expect easily to hit our target of 23% to 27% versus last year. Still vertical integration and doing a great job of saving cost. Whether it's pumping services, pulling units, drilling rigs, we're seeing substantial savings versus our peer groups on all the offset wells that we see, that we participate in. Then, finally we have a great set of hedges in place. Gas goes out to about 2014, great hedges in place. Oil starting to increase in 2014, but very high percentages in '12 and '13 and finally, a strong financial position, and we will continue that way.

Let me turn it over to Tim to get into the operating assets.

Timothy L. Dove

Thanks, Scott. The first quarter, as he has already described, was a very strong operational quarter for the company. As opposed to the first quarter of 2011, we did not have any significant weather effects in the first quarter of 2012, and also, we benefited because we maintained what was very close to the same rig count as we had at year-end 2011. So the result of that is we were able to bring out several operational efficiencies, such as Scott mentioned, for example, reducing the frac bank, which incrementally added production.

My first slide is Slide 9, and on there, we were discussing the ramp-up in more detail regarding the horizontal Wolfcamp Shale play. Scott has already alluded to, we're focused on the southern 200,000 acres where we're trying to preserve leasehold. Importantly, our first 2 wells in the Giddings area, shown in the red stars on the map, continue to flow naturally at very strong rates. In fact, the first of those 2 wells has already made 77,000 BOE in a little over 200 days.

So that bodes well considering the vertical alternatives drilling into the Wolfcamp. Generally speaking, we use a type curve of 140,000 BOE. So that gives you a view that these are very, very strong wells, and we still calculate that they are making roughly 7x what a vertical well would make in the same time period. That's for each of the 2 wells. That's very positive news. These wells continue to hold up, and actually, it's really an outstanding result. They continue to flow naturally at such strong rates.

As Scott mentioned also, we drilled 3 wells in the first quarter in the horizontal play. And as he mentioned, we put 2 of those on production just in the last several days. We had some delay in putting infrastructure in place, and we're providing for the jet pumps and the equipment necessary for gas lift, and those are now in place and producing. As Scott mentioned, they're mostly producing water, but we are seeing oil cuts increasing on a daily basis. So we're excited to see how those wells finally work out.

In a bigger picture sense, we're going to be drilling 9 more wells in the second quarter, as we ramp up with our 4 rig program, and we think it'll be about 2 or 3 of those wells will be getting on production by the end of the second quarter. The rigs that are coming to the rest of the year are already contracted. We plan to be at 7 by the end of the year and 10 in 2013 on average, and what that will allow us to do is to drill those 90 wells that would be necessary by the time -- the end of 2013 comes to have those wells on production.

We did successfully add some bolt-on acreage, about 17,000 net acres in the southern area of the play. Some of that, of course, is necessary to provide for longer lateral lengths on the horizontals. So in a lot of cases, we're just acquiring adjacent acreage to current leasehold. So I will say overall, the horizontal Wolfcamp play is going extremely well. The drilling program is ramping up on schedule.

Slide 10 then is regarding the vertical campaign. Vertical campaign is really the backbone of our current growth in the Spraberry Trend Area, and we continue to see significant contributions from the deepening of the wells. This slide, Slide 10, shows results from each of the 3 different zones that we're targeting. So for example, on the Strawn, we have 81 wells on production, with Strawn having been completed. We have always been in the thought area that we will be 30,000 barrels incrementally from the Strawn, and we continue to believe that.

What has happened though is we now believe it was prospective on a little bit more of our acreage than we once thought after some new mapping. We originally had it targeted for about 50% to 60% of our acreage, and now we believe it's prospective along somewhere in the neighborhood of 60% to 70% of the acreage. Very strong results have been seen in the Atoka, where we put 29 wells on production, so really phenomenal zonal test we were just producing in the Atoka.

You can see on the chart that we've had IPs in the 150 to 250 BOE per day rate from the one zone. So that gives you the idea they can have really significant potential in terms of adding to EUR, and we think the results we've seen to date still suggest a 50,000 to 70,000 BOE EUR add for the Atoka completion. And we still believe it's in the neighborhood of 25% to 50% of our acreage in terms of its prospectivity.

Less activity in the Mississippi and about 8 wells put on production. We still see 15,000 BOE to 40,000 BOE, and it being prospective of something like 20% of our acreage. So the vertical campaign is very critical to our go-forward plan and particularly regarding deepening. You can see on Slide 11 that we've got a massive campaign in place for the deepening program, as we complete the rest of this year.

As we have already discussed, we're currently running 40 vertical rigs in the play and will eventually decrease that to about 30 during the second half of the year, with the idea of accommodating the expansion of the horizontal campaign, which is much more capital-intensive. On the graph you can see the deepest interval to be completed. About 50% of the wells, for instance, will be completed, with the Wolfcamp being that deepest interval. And you could see the rest of the table, the actual cost on a blended basis, and the returns are very strong. The cost incidentally is still being helped very considerably by our pumping -- Pioneer pumping services. We're saving over $200,000 per well by pumping our own wells.

Now turning to Slide 12. Well, the bottom line is as a result of what I've just been discussing, this asset is hitting on all cylinders. You can see first quarter production about 62,000 barrels a day on a BOE basis. That's up 9,000 from the fourth quarter of 2011, which is at 53,000. Some of that, of course, is attributable to efficiency gains. During -- quite a bit of that period, we were running our frac fleets 24 hours a day, and also, to the extent we had a flat rig count, we were able to really bring out efficiencies, and related to that, we reduced our frac bank something like 40 wells, which added to the production in the first quarter.

You can see here looking forward, and I think the first quarter is representative of this, we have an asset here that can grow substantially on a low-risk basis, predictable basis. That's why if you look forward to our planning numbers production, we think that we can either exceed these targets.

Going to Slide 13 and turning to Eagle Ford. Well, the Eagle Ford Shale is also humming along, I would say. We drilled 28 wells in the first quarter. We have 26 wells on production. We still have a flat rig count, which is helping, again, from an efficiency standpoint. We're running 12 rigs. At one point, we thought we'd move into 14 rigs, however, we've dropped 2 rigs in consideration of low natural gas prices.

In fact, of the 125 wells we're going to drill this year, only about 15% will target dry gas in strategic areas where we can preserve a lot of drilling locations for the future. That was originally going to be 25%. So in response to low natural gas prices, we have adjusted the well count and the rig count. We continue to see a lot of benefits from using white sand as a proppant. 45 wells have already been stimulated using white sand, and they look good as compared to their ceramic-stimulated offsets. It saves upwards of $700,000 or more on each well.

So combining that with our vertical integration where we have 2 frac fleets running in the Eagle Ford Shale, we have a substantial cost advantage compared to our peers in that play. And importantly, we're on top of the infrastructure game, too. We added one more CGP, central gas processing facility, and have 2 more planned for the midpart of this year.

And so we have really no bottlenecks that are in our way to grow production, as shown on Slide 14. We were up to 23,000 BOE a day in the first quarter, up from 20,000 in the fourth quarter of 2011. And so as I look forward to this, we think that we're on target with this year's guidance, and as we go forward, our rig count will be increasing as the current plan to 14 in 2013 and then upwards of 19 rigs in 2015. And so I think this growth is achievable in the Eagle Ford Shale as well.

Turning to Slide 15, the Barnett Shale Combo play. It had a good operational quarter as well, drilled 9 wells, put 10 on production. That continued to be very consistent. We're doing some work in terms of making sure we can get water off these wells on a faster basis. We still plan to increase to 4 rigs next year. You may recall we held off, for the time being, moving to 4 rigs simply because in a low gas price environment the economics are affected negatively in this play since about 40% of the production is gas. I think we will probably move to 4 rigs next year in consideration of the need to preserve leasehold.

And then the results of that, Slide 16, is about a 7% sequential growth in the Barnett Shale compared to the fourth quarter where we produced, in the first quarter, still about 6,000 BOE per day. But that'll be growing as we continue in the drilling campaign this year. We're on target for our full year guidance. And as the slide shows, we are contemplating going to those 4 rigs in 2013

I would note that all 3 of these key growth areas, we were talking about Spraberry Trend area, vertical and horizontal; Eagle Ford Shale; and Barnett Shale are all on target for the production growth, which gives us confidence in this year's forecast.

Finally, some positive news. We have 40 in Alaska. Scott has already alluded to this, but I'll give you a little more detail on Slide 17. The Torok well that he mentioned, where we had a success, was drilled on 100% working interest basis to Pioneer. If you look at the map on Slide 17, you can see where this well was drilled as designated with a star, and this tested the southern extent of the accumulation. And to the extent this is a very positive well, one of the best wells we drilled on the Torok, making an IP rate of about 2,000 barrels a day. It gives us confidence we've added pretty substantial resources, maybe 50 million barrels of oil.

We produced the well for several days, and we're, of course, forced to move off the ice in the face of the breakup as the weather was warming. But as Scott mentioned, we probably will look at potentially producing this well next winter and testing it further in doing so and potentially drill another well in this area to firm up our development planning.

The Ivishak exploration well was unsuccessful. The principal target being the Ivishak zone was wet. It did have some gas in another zone, but gas in this area is basically noncommercial, so this well was P&A. The drilling campaign on the island continues where we have one rig drilling a series of different zones, including the Torok. Interestingly, the most recent Nuiqsut well, was completed with a mechanically diverted frac, made 4,000 barrels a day, by far, our best Nuiqsut well. And that's very encouraging looking forward because we think this style of drilling and completion we can also use in applicability for other Nuiqsut development wells going forward.

So in summary, I'm going to stop there. But the first quarter was a very strong operational quarter for Pioneer, I didn't mention it and we should mention it more. But we couldn't have accomplished this kind of production growth without a very solid performance in our other gassier areas, so here I'm speaking, of course, of Raton, Mid-Continent and our south Texas Edwards teams, which all did a phenomenal job in the quarter.

So with that, I'm going to turn the call over to Rich for a discussion of the first quarter financials and the second quarter outlook.

Richard P. Dealy

Great. Thanks, Tim. I'm going to start on Slide 18. Net income attributable to common stockholders was $215 million or $1.68 per diluted share. It did include a couple of unusual items that are listed on the page, as well as unrealized mark-to-market derivative gains. If you adjust for those items, our earnings was $153 million or $1.23 per share.

Looking at the bottom of the slide, Scott and Tim both talked about production and the good results there. A couple of items just to note, exploration abandonment for $53 million for the quarter does include the unsuccessful well that Tim talked about in Alaska for $19 million and included seismic that we acquired in the horizontal Wolfcamp and Barnett Shale for $11 million.

G&A at $63 million really reflects the increase in staffing that we've done to support our growth and then some restricted stock retention awards that we've done, as well as the timing of some Cherouq [ph] donations that were front-end loaded in 2012. On current income taxes, the only difference there being $12 million as we now are projecting to pay some AMT tax in 2012, and that's the reason for the increase.

Turning to Slide 19, price realization. On the bar charts there, you could see that oil was up 8% from the fourth quarter to $99.15. NGL prices were down 8.5% to $41.81 per barrel, really reflecting lower ethane and propane prices throughout the quarter. And as you guys are aware, gas prices were down 26% to $2.51 per Mcf.

Now looking at the bottom of the slide, you can see the impact of the VPPs. And as you recall, they do run off at the end of this year so those will go away, and then there's a small impact that's related to derivatives that are included in our prices, and those also run off at the end of the year. So really after this year, all we'd be left with is derivatives, and you can see the impact based on our derivative portfolio.

Turning to Slide 20, production cost. The message here is that production cost has been flat for the past year. The asset teams continue to do a great job in managing those costs, and so we look forward for that to continue.

Turning to Slide 21, on guidance. Production guidance for the second quarter, 149,000 to 154,000 BOE per day, so we continue to ramp up on the production side. Exploration abandonment of $25 million to $50 million does reflect some carryover activity on Alaska, that unsuccessful well that was -- activity in April that will hit the second quarter, and then incremental Wolfcamp and Barnett Shale seismic that will be shot in the second quarter. The other items are consistent with first quarter results or past guidance, so they're there for your information. I won't go through each one individually.

But that really concludes my comments. So at this point, we'll go ahead and open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Dave Kistler with Simmons & Company.

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

Real quickly with respect to the inventory of wells in the frac bank that came online, can you just give us an estimate of what that meant to quarterly production?

Timothy L. Dove

The 40 wells that I've discussed, Dave, contributed about 1,000 to 1,500 barrels of oil equivalent per day for the quarter.

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

Okay. That's helpful. And then with your comments on Alaska and the success you guys had with the Torok well, comments that you're going to go ahead and continue the drilling program next winter. Previously this, I guess, has been discussed as a potential divestiture candidate. Is that off the table?

Scott D. Sheffield

We're finding out that the diverted fracs on both the Torok, and also Nuiqsut. We have several more candidates on the Nuiqsut, and we are going to be evaluating that over the next several weeks and months to determine if there's a strong potential we could really ramp up production growth in that area. And it looks like that we may definitely be needing to drill another Torok well next winter.

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

Okay. Appreciate that. And then just one kind of thinking more about the service cost side of things. Obviously, you're vertically integrated both in the Eagle Ford and the Permian and feels like there's pockets of softness on the service side in the Eagle Ford but definitely firmness in the Permian. Can you talk about whether you would or could redirect your vertical integration teams, efforts, equipment from the Eagle Ford to the Permian so you could take advantage of any kind of cost weakness that's taking place in the Eagle Ford versus the Permian?

Timothy L. Dove

Dave, this is Tim. Let me just say this first of all, we are noticing in certain areas a little bit of softness when it comes to pumping services, but in general, that's coming off a very high peak. We're basically insulated from that, as you might guess, mostly because in the Eagle Ford Shale we have 2 of our own fleets running, as well as a third-party fleet, which suffices for all of our drilling campaign this year. So those activities will take care of our drilling campaign there. In the Permian basin, we have 5 of our own fleets going to 6 here shortly this summer -- and actually 6 going to 7, I guess, when we consider the last one coming in. And my point there is we are self-sufficient to a great extent now in the Permian basin. So we're still making quite a lot of money on VI related to the fact that we can still do this cheaper than we're being charged by third parties. We still have very large savings after even a little bit of softness in both of these areas.

Operator

We'll move on to Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I guess just curious a little bit on the horizontal program in the Permian. Obviously, the thought process was to ramp that up while you kind of ramp down the vertical program. Is there any ability or desire to, I guess, accelerate those efforts at all in 2012? And if not to fully accelerate them, maybe just to pull forward some of the horizontal activity, is there any ability to do that?

Scott D. Sheffield

Well, we're already in the process of accelerating the horizontal Wolfcamp activity. We're moving up to 10 rigs fairly quickly over the next few months.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I guess I'm saying about even further than current plans.

Scott D. Sheffield

Our focus right now -- I mean, obviously, we continue to make great wells like we have in Giddings, then we will continue to, going into '13, '14, '15, probably look at accelerating the Wolfcamp program. We'll eventually need to be going north in the Midland county. We need to be drilling some Wolfcamp A zones, C zones and D zones. So this is probably a good chance, but we need more data points. And we would like, at some point in time, if we see our oil prices, to be able to keep a good strong vertical program going. Right now, we're going to 30 rigs starting later in the summer on the vertical program, but we'd like to run a little bit more than that. We might be able to get back up to 40 sometime in the next year or 2. So we'd like to be able to move the rig count up on both sides over the next 2 to 3 years.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

That's helpful. And then, in the Eagle Ford, I'm just curious on the 125 wells. Are all those planning to be tied into sales? And is there kind of a back-loaded nature to that?

Timothy L. Dove

No, I think we'll be doing it ratably throughout the year. You can see that we've had a good start on that first quarter, and I think that will just continue as we drill with the same number of rigs throughout the entire year. Kind of the frac bank there is -- we can easily handle our frac bank there with the 3 fleets, so it will be very steady as she goes.

Operator

From Stephens, Will Green has our next question.

Will Green - Stephens Inc., Research Division

I wonder if you guys could help break down kind of the $8 million to $9 million on kind of the science wells for this horizontal Wolfcamps, how those get to $6 million to $7 million. How should we think about kind of, I guess, the sum of parts, for lack of a better term, with the 8 to 9 and then the same for 6 to 7?

Timothy L. Dove

Well, if you look at the science wells compared to what we consider to be more of a traditional development well, the way it calculates out is this, the drilling just because we won't be needing pilot holes and we can more quickly drill the wells, we think would be $700,000 less, especially when we're developing drilling mode. We also do cores in these wells typically from a science standpoint. That's about $500,000 or so. We have micro seismic typically done as we're trying to understand how the fracs propagate, and that's about $400,000. We do extra and very significant logging suites, which is about another $400,000 compared to what you were doing on a development well. So when you're done, that's $2 million, which is really not necessary in connection with just normal development drilling.

Will Green - Stephens Inc., Research Division

Great. And then, how can I think about the drilling versus the completion side of that final cost?

Timothy L. Dove

What the split is, is your question?

Will Green - Stephens Inc., Research Division

Yes, yes.

Timothy L. Dove

Where in a 6 to -- let's say, $6 million to $7 million well, it'll be about a $2 million completion is the current thinking. The rest of that will be drilling.

Will Green - Stephens Inc., Research Division

Okay, great. And then, I wonder if you guys could touch on your current thoughts on takeaway capacity in the Permian. How should we think about the differentials in the Permian now? And then, going forward, do you think that there's enough midstream that's coming online to really take care of that? I wonder if you guys could just touch on that.

Scott D. Sheffield

Yes. Over the next 2 areas, there's enough expansions right now with Plains All American Basin Pipeline and the Magellan line coming on the first quarter next year, and it was good to see -- I think you'll see something eventually come out of the Energy Transfer acquisition of SUN because that western gulf line could probably easily be expanded. I think that's the next major thing that you'll see once that acquisition is completed by Energy Transfer. We still need another 400,000, 500,000 barrels a day by 2020 to get to 2 million barrels today. But I don't see really any big issues for the next couple of years. So we need to get some other lines in place by 2015 really to solve the next big increase. The Permian is growing at about 150,000 barrels a day of oil per year. I think there shouldn't be any issues. The recent WTI, West Texas, versus Cushing has come back within $3 or $4. I'd like to see it get back to about -- obviously, it went back $0.50 to $1 dollar. But it has come back off that $8 to $9, and most of the maintenance projects turnarounds have been completed at the refineries that are in the area.

Timothy L. Dove

Just one more note related to that is on the gas side, you may remember we are expanding our Midkift/Benedum facility with Atlas by 100 million cubic feet a day in early 2013, and potentially, that amount again by the end of 2013. So Scott didn't touch on the gas side, but we're well in advance of any issues on gas by those expansions.

Operator

We'll move on to Jessica Chipman with Tudor, Pickering & Holt.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Two questions for me. The first just on the 2 wells you've drilled so far on the horizontal Wolfcamp, do you have a preliminary estimate for an oil and gas mix on the EURs of those 2 wells?

Scott D. Sheffield

Yes, it's 90% liquids. We're still going with 80% oil, 10% NGLs, 10% gas on the reserve mix. And so it's only -- we haven't seen it change. It's been fairly steady at those splits for the first 6, 7 months, full months.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then, just secondly, thinking about Q2 guidance as almost flat with 2012 guidance, how do we think about the back half of the year? Is there a reason to think that production will continue to stay flat? Is it just really vertical rigs going down on Spraberry offset by some Wolfcamp upside?

Richard P. Dealy

No, it's a combination of the frac bank. You remember the frac bank was -- came down significantly first quarter in the Permian basin. And also, we'll be ramping up the -- I mean, ramping down the vertical from 40 to 30 rigs. All the major items, that's why you're not going to see a big ramp-up second quarter.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And on back half of the year?

Richard P. Dealy

Yes.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

So at the end of this quarter, how many wells were left waiting on completion in, I'll use the word, frac bank?

Timothy L. Dove

The Permian basin were 60 to 70 wells in the frac bank at the end of the quarter; Eagle Ford Shale, about 10; Barnett, 3 or 4, 5 wells.

Operator

Next question will come from Leo Mariani with RBC Capital Markets.

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

Quick question on Alaska. Obviously, some nice drilling success this quarter. Do you guys expect production to go up at all this summer? Or is that something more we have to kind of wait for next winter? I know it's been hanging in there around 4,000 barrels a day.

Scott D. Sheffield

The Torok well that Tim and I mentioned, Leo, is -- it was suspended, so it's not producing. But the Nuiqsut well is still producing 4,000. We've been doing it for about 2 or 3 weeks. We just need to watch it. Obviously, if it does -- if it hangs in there in the 4,000 range or even 3,000, we should get a nice bump, obviously, over the next several months.

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

Okay. In terms of your Wolfcamp program, you guys had originally talked about having 200,000 acres in the southern Midland basin, your big focus area. Visually, in your, slides, you've been saying 400,000 acres of potential. What gives you confidence in that additional 200,000 acres there?

Scott D. Sheffield

If you just move -- if you just count the Giddings. If you look at that map, our map of the 200,000 southern acres is sort of south of Giddings. So the Giddings well is -- essentially, if you move to east of Giddings and stay south of Midland county, that's how you get to the 400,000 acres. So the Giddings well sort of sets that up. The 200,000 acres originally came from all the offset operators: EOG, Approach, El Paso's drilling and Devon's to the south, so that was the original 200,000 acres. Those are in the, basically, the 4 boxes on Slide #9. But in Giddings, you can see we have a massive amount of acreage around Giddings and back to the east. That's how you get to the 400,000, adds another 200,000 acres.

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

Okay. And I guess, in the Wolfcamp you picked up more acreage this quarter. Any estimate of how much additional acreage you think you'll have to pick up over time in order to make all your drilling units?

Scott D. Sheffield

It's hard to tell. We have still some offers out there. I think a lot of deals over time are going to be farm-out and may be less acreage. I think some people have indicated they want to drill with this, but we don't want to put additional rigs to work. So I think it'll probably come-- I don't think we'll do 17,000 acres second quarter, for instance. It may come in third or fourth quarter some more acreage. But we'll probably see more and more farm-outs over time also over the next couple of years as this play develops.

Operator

Next question will come from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

And maybe more big picture. I mean, as we look at the presentation, all the core areas in Texas move up into the right. And it seems like you almost -- could potentially have unlimited inventory in the Permian. I mean, how do you allocate capital going forward? And is there a way to accelerate that? And how willing are you to kind of lever up the balance sheet a little bit?

Scott D. Sheffield

As I've mentioned over the last several weeks, at Joe's [ph] conference and other people's conferences that first of all, we need to really prove up. We're excited about the Wolfcamp play. We really need to prove it up, and then we have, obviously, several items' access to us. Whether it's a JV or whether it's capital markets or whether it's potential divestitures down the road, we will look at all of those. And so it is going to be a good year before you make a decision on any of those items and decide, and it could be more cash flow from higher oil prices or better growth rates. So we're just going to evaluate all the opportunities, Brian, at this point in time.

Brian M. Corales - Howard Weil Incorporated, Research Division

And what's your comfort level? I mean, the balance sheet is obviously pretty clean. Is there a certain metric that you look at like debt to EBITDA? Or where the comfort level is for you guys?

Scott D. Sheffield

We're going to hit debt to EBITDA of 1 next year, in 2013, and so we like to -- most of our peers that are around us and above us, our at 1 or better. So we feel like that's a great target to stay within. So as our cash flow goes above that, then we don't mind using some of the balance sheet as long as it stays debt to EBITDA of 1 or less.

Operator

Next question from Stifel is Amir Arif.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

A couple of quick questions. The 3 horizontal Wolfcamp wells you drilled in Q1, where those also targeting the B bench? Or have you started already targeting some of the other benches out there?

Timothy L. Dove

Those were all B-bench-targeted.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then, when do you start one? I know you talked about starting to target some of the others, does that happen in 2Q? Or is that a '13 event?

Scott D. Sheffield

I think it's about end of the year, the A.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

The end of the year. And then, as you ramp up to 10 rigs on the horizontal side, that can be enough -- that should be enough to capture the 200,000 acres. But now that you're talking about 400,000 acres, do you need to accelerate further? Or is that held by production, the other 200,000?

Scott D. Sheffield

Yes. It's only 50,000 acres that we have expiring. So that's what the focus is. The 50,000 is within the 200,000 that we talked about, the southern part of the play. We do have 50,000 acres expiring by November 2013. So the rig count is designed to hold those 50,000 acres. It preserves about 400 drilling locations.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. Then just a final question on the vertical rig count. As it goes down from 40 to 30, which kind of wells are you not going to be drilling, the deeper ones or is it certain geographical areas? Or how are you thinking about that?

Scott D. Sheffield

It's probably going to most likely be -- our returns are better as we go deeper. So if we do drop some, it will be wells that are targeting the bottom of the Wolfcamp.

Operator

Moving on to Sven Del Pozzo with IHS.

Sven Del Pozzo - IHS Herold, Inc

My question, what are the main factors that make you think the C1 and the D bench of the Wolfcamp more localized than what you've been drilling so far in the horizontal Wolfcamp?

Scott D. Sheffield

It's primarily due to our extensive array of log data and core data that we have than most peers. We've been in the field for 50 years, and we just have the largest set of data. We've done lots of work over the last 2 or 3 years, and so we feel like the D and the C is more localized than certain areas. The A and the B is more widespread. And the A and the B have much more oil in place, also based on that same data.

Sven Del Pozzo - IHS Herold, Inc

And what about silica content?

Scott D. Sheffield

Silica content, I think, we have a good slide, I don't know if it's in this presentation. Is it in back?

Timothy L. Dove

It's in the Doug [ph] Conference one.

Scott D. Sheffield

It's a slide that we show compared to other shale plays, and we have very, very strong silica content throughout, especially the A and the B. I can't answer about the C and the D zone.

Sven Del Pozzo - IHS Herold, Inc

Okay. And then 140 acre spacing I've seen for the horizontal Wolfcamp, is that just including one bench?

Scott D. Sheffield

Yes. 1 billion barrels is just one bench, 140-acre spacing.

Sven Del Pozzo - IHS Herold, Inc

Okay. Then back to that previous question about the science wells versus development wells and the difference in cost. If you've already got course from older wells, are those -- is that $400,000 in savings right there for a development well?

Timothy L. Dove

We're coring wells in some of these newer areas to the south where we don't have as much data because we have not been doing as much vertical drilling. As you may remember the vertical campaign starts to pewter out as you go south in terms of productivity of the wells. And so therefore, we don't have quite as much data in the south. That's why we are spending money on science in the early part of this campaign. Most of the science drilling will be done by this summer.

Sven Del Pozzo - IHS Herold, Inc

Okay. Depletion expense. It looked like DD&A just stayed flat or even down sequentially in the quarter even though production went up. Wondering why.

Richard P. Dealy

It's just on a per BOE basis that it stayed flat. And then as you recall, we had an impairment charge in the fourth quarter for south Texas and so that lowered that depletion rate.

Sven Del Pozzo - IHS Herold, Inc

Okay. And very last question, your NGL realizations still seemed pretty strong despite the spot market price decline. What are some of the reasons for that?

Richard P. Dealy

Really nothing out of the ordinary just business as usual. We've been selling in the same market. A weak ethane and propane prices, but other than that everything else was -- we probably got a little benefit because oil prices were higher, so the heavier end of the stream was better realizations.

Operator

Moving on. From Global Hunters, Dan Morrison.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Most of my questions have been answered. But the stage frac in Alaska, what was the cost on that well?

Scott D. Sheffield

I think we spent -- on the 2 Alaska wells, we spent a little over $50 million or 100%. 100% on both wells.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

You said you thought you had several more locations.

Scott D. Sheffield

That was on the Nuiqsut. Nuiqsut, we are reaching from the island. It's a primarily reserve base producing formation off the island, and the Nuiqsut well that made 4,000, it was a -- had plug and perf technique off the island, and that's where we have several more potential candidates we'll be looking at.

Operator

We'll move on to Charles Meade with Johnson Rice.

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

First, on the Eagle Ford midstream, there's some people off to the west of where you guys are talking about problems with a Regency and a Kinder processing facility. Another is off to the west to you. But my question is will you, in any way, be affected by that? And if something like that would happen closer where you guys are, would your CGP going to insulate you from the effects of that?

Timothy L. Dove

The answer to your first question is no, no effect from any of their issues. Secondly, we're working with different set of parties in terms of offtake, and actually the big news for us is we're having our own oil pipeline midpart 2012 as opposed to being trucked today. But we don't have any kind of those infrastructure issues. We are, as you know, Charles, sort of have a leadership position because we're the first mover on all this infrastructure.

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

Right, great. Good to hear. Second question, on the -- this is another horizontal Wolfcamp question. One of your competitors talked about a horizontal Wolfcamp well they drilled in southeast Ector County, so well to the northwest of the activity you and EOG and everyone else has been targeting. I believe they said it was in the Odessa south area. I know you guys aren't focused on that right now, but could you offer any commentary if you have a view if the trend would extend that far because if it does then you're talking about a lot more than 400,000 acres?

Scott D. Sheffield

Yes, that well, I think, it was about first 30 days, if I recall the note I read, our 2 Giddings wells is about 50% better than that well on the first 30 days. The rate looks pretty good but that's pretty much where the Wolfberry play was coined over the last 3 or 4 years on the west side of the play. And so the Wolfcamp does go up that far. We don't think the maturity and the depth is as good as the center part of the basin. There's also -- we've been asked there are several people drilling wells now in Terry County, way to the north. If they find it out in Ector County and find it out in Terry County, it's going to be in 3 million, 4 million acre play. So it's going to even -- the number is going to be even greater than what you're saying, so we just got to wait on results. So you got Glasscock and people moving east and Glasscock looking for the Wolfcamp. And they're going way north, and now they're going west. We still feel like the center part of the play, where our acreage is, is the best part.

Operator

Moving on to Rehan Rashid with FBR.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Have you got any thoughts on what portion of your acreage is exposed to the Cline?

Scott D. Sheffield

We have a lot of fine acreage in Glasscock County. I would estimate 100,000 to 130,000 acres. We have a good potential, but right now it's just -- we show less oil in place on our data points. It still looks like it could be a good play. But we're going to be focused primarily on holding this acreage and eventually drilling mostly in the center part of our acreage where we think the best maturity is, better reservoir pressures, less clay content, higher quartz, silica. And so that's where you'll eventually see us do most of our drilling, but that's going to be focused on the A and B. We'll let the other operators prove up the Wolfcamp D or the Cline on the eastern side.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Okay. And going back to Alaska real quick. So is that sometime next year where we had a point whether we decide to keep Alaska as a long-term quorum asset or kind of jettison it, any thoughts on timing to come to that decision?

Scott D. Sheffield

Yes. As you noticed the production has been flat or on a decline in the last 12 months. If the team up there can show us they have huge potential to grow production and frac several more Nuiqsut wells and look at some Torok, then we'll look at keeping and keep growing it. And so that's the key, do we have enough upside on growth to able to reinvest the cash flow and grow the asset. And we love growing assets.

Rehan Rashid - FBR Capital Markets & Co., Research Division

But do you get to that point middle of next year, late next year in terms of making that decision?

Scott D. Sheffield

That decision we can make it down the road, yes. We have that decision in all of our assets.

Operator

From Goldman Sachs, Brian Singer has our next question.

Brian Singer - Goldman Sachs Group Inc., Research Division

Most of my questions have been answered. But can you just talk to where within your Permian position you're acquiring the 260 square miles of 3D seismic and what you hope to take from that? Is that within the 200,000 acres that you've already deemed prospective or is that towards expanding -- or 400,000? Or is that towards expanding that reach?

Scott D. Sheffield

Yes, it's mostly Upton, Reagan County right now, and it's obviously to identify faults to make sure we stay away from faults, primarily.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got it. And then, on the Barnett Combo, can you just kind of talk about that asset in the context of what you're seeing in the Permian? And whether that -- you've identified a major -- identified that asset as a source of growth over the next couple of years, but how does that rank in terms of scale strategically versus the Permian? And in the context of potentially accelerating the Permian, is that a potential candidate for divestiture?

Timothy L. Dove

Brian, I'd just say that, at this point in time, we're in the process of ramping up Barnett, with -- the drilling campaign is going to increase next year. I really look at it as a fourth leg on a stool, if you will, in terms of production growth in Texas. And we've got an excellent team in the Barnett Shale Combo play that's uncovering a lot of the puzzle, and so we're doing an excellent job of growing production there looking forward. And I would really see it as 1 of our 4 growth assets in Texas and probably planning to keep it that way.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then, lastly, you touched on this a little bit earlier in terms of the potential -- the cost reductions that will be coming in the horizontal Wolfcamp as you do less science. When would you expect to achieve that? Is that something that you think is a year out, 6 months out? When do you -- when should we expect that?

Scott D. Sheffield

I think by the end of the first half of this year, Brian, we will have most of the science wells drilled or we've collected data in -- where we're going to be drilling the majority of the wells in the south. And at that point, we'll go to more of a development drilling style of campaign.

Operator

We'll take a follow-up question from Dan Morrison with Global Hunter.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Back to the crude oil takeaway issues in the Permian. Have you all got access on the Longhorn system of any capacity? Or is that pretty much held by marketing companies?

Scott D. Sheffield

Yes. We do have some takeaway capacity. I don't know if we disclosed it . Have we?

Timothy L. Dove

No, we haven't.

Scott D. Sheffield

We can't disclose it due to our agreement with Magellan, but we do have -- we did take away specific takeaway capacity on that pipeline.

Operator

We have no further questions at this time. I'll turn the conference back over to you, Mr. Sheffield, for any closing additional remarks.

Scott D. Sheffield

Again, thanks for listening to another great quarter. We look forward to seeing you out on the road or the conferences. Or the ones -- we'll see you at the next quarter. Again, have a great spring, early summer. I hope it's hot in certain areas so we can burn some more natural gas. Thank you.

Operator

And ladies and gentlemen, that does conclude today's conference. We thank you for your participation. Have a good day.

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