先鋒自然資源 (PXD) 2012 Q1 法說會逐字稿

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 provision 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 and 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 the Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

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. He'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'll open up the call for your questions. And with that, I'll turn the call over to Scott.

Thanks, Frank. Good morning. On slide number 3 on our highlights, as Frank said, we had another great quarter. We had adjusted income of $153 million or $1.23 per adjusted share. On production, we were over our range on the production side first quarter at 147,000 barrels of oil equivalent per day. That is a pick-up of about 10,000 barrels a day for the quarter versus the previous quarter, about 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.

Still highly encouraged by the entire play that we are seeing in the Horizontal Wolfcamp play, we still feel like it will be probably the biggest oil play within the US over the next several years. We're up to four 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 -- the 20 months. We just brought on two recent wells on artificial lift. One is on jet pump, and one is on gas lift. They are making mostly water at this point in time.

We are still continuing to have great success by going deeper to the Strawn, Atoka and Mississippian intervals in the Spraberry field, one of the primary reasons that we are seeing continued great success this past quarter in the Permian Basin. In the Eagle Ford, we ended our ninth CGP. Expect two additional CGPs online by mid-year. In Alaska, we had recent success with a couple key wells. One was onshore, the Torok, where we have drilled several wells on the island.

We did a plug and perf technique on shore and got a 2000 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 a 50 million barrel a day discovery. And, secondly, what may be 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 4000 barrel a day rate there. Tim will talk more about this later on.

We completed our acquisition for the Sands business. We have 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. Expect additional 45,000 by mid-year for total of 300,000 horsepower for the Company. We added some recent oil derivatives positions, primarily in 2014 that will continue to increase the percentage in the later year of 2014 on the oil side. And then as we had mentioned before that we were close to agreements. So 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 number 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 and still on track to deliver our 20% CAGR over the next three years. One note, we are already up to 58% liquids in the first quarter of 2012 moving up to 65% liquids in 2014.

Slide number 5 on capital spending and cash flow. Our capital budget is remaining the same at drilling on $2.4 billion and about $400 million on broke integration. We are front-end loaded in 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 lots of science in the first half on 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 tag. Hopefully, it will come in at least that high and maybe even higher.

Slide number 6. Great operating cash flow for the Company, again $2.2 billion. That is based on $100 oil and $3 gas for 2012, climbing on up to $2.8 billion next year for 2013 and over the next three years a 25% CAGR compounded growth rate. 80% revenue moving up to 90% revenue, I think we are estimating about 83% of our revenue will be from liquids in 2012.

Slide number 7, we used this slide recently at a recent conference so we did not show it at the last quarter's call. It's an update on our resource potential on slide number 7, significant proved reserves and resource potential. The big change is primarily on in the Permian Basin, primarily continuing to add deeper potential for the Strawn, Mississippian and Atoka reserves, continuing to see great results from our 20-acre drilling.

And then we added 1 billion barrels of oil equivalent to 3000 Horizontal Wolfcamp locations. This is only targeting the B -- the Wolfcamp B formation. We'll eventually be planning both A Wolfcamp and also C Wolfcamp and eventually some more climbs over the next 12 to 18 months, so we -- huge upside potential to that 1 billion barrels of oil equivalent potential.

Slide number 8, investment highlights. With the divestiture of South Africa, we're now back to a solely 100% US asset base. We have over 30,000 liquids-rich drilling locations with resource potential of over 5 billion barrels of oil equivalent. The third most active driller now with our 2012 program focused on four great plays delivering one of the highest compounded annual production growth rate over the next three years, and cash flow growth rate of 20% to 25%. With first-quarter results, we expect easily to hit our target of 23% to 27% versus last year.

Still vertical integration, doing a great job of saving costs. Whether it's pumping services, pulling units, drilling rigs, we're seeing substantial savings versus our peer groups on all the [offset] of wells that we see that we participate in. And 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'll continue that way.

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

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. The result of that is we were able to wring 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 are discussing the ramp-up in more detail regarding the Horizontal Wolfcamp Shale play. As Scott has already alluded to, we are focused on the southern 200,000 acres where we are trying to preserve a leasehold. Importantly, our first two wells in the Giddings area, as shown in the red stars on the map, continue to flow naturally at very strong rates. In fact, the first of those two 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 tight curve of 140,000 BOE.

So, it gives you a view that these are very, very strong wells, and we still calculate that they are making roughly 7 times what a vertical well would make in the same time period. That's for each of the two wells. So it is very positive news these wells continue to hold up, and, actually, really an outstanding result they continue to flow naturally at such strong rates.

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

In the bigger picture sense, we are going to be drilling nine more wells in the second quarter as we ramp up with our four rig program. We think it will be about two to three of those wells will be getting on production by the end of the second quarter. The rigs that are coming through 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 will 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 are just acquiring adjacent acreage to current leasehold. So I would 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. The 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 the results from each of the three different zones that we're targeting. So, for example in the Strawn, we've put 81 wells on production with Strawn having been completed. We have always been in the thought area that it would be 30,000 barrels incrementally from the Strawn and we continue to believe that. What has happened, though, is we now believe that it was prospective on a little bit more or 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 on 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. Some really phenomenal zonal tests where we were just producing in the Atoka. You can see on the chart that we have had IPs in the 150 to 250 BOE per day range from the one zone. So that gives you the idea that it can have really significant potential in terms of adding to EUR. And we think the results we have 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 Mississippian, about eight wells put on production. We still see 15,000 to 40,000 BOE, and it's being prospective on something like 20% of our acreage. So the vertical campaign is very critical to our go forward plan, particularly regarding deepening. You can see on Slide 11, 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 we'll eventually decrease that to about 30 during the second half of year with the idea of accommodating the expansion of the horizontal campaign which is much more capital extensive.

On the graph, you can see the deepest interval to be completed about 50% of the well, for instance, will be completed with the Wolfcamp being the deepest interval, and you can 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 Pioneer Pumping Services where we are 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 have just been discussing, this asset is hitting on all cylinders. You can see first-quarter production at about 62,000 barrels a day on a BOE basis. That is up 9,000 from the fourth quarter of 2011 which is 53,000. Some of that, of course, is attributable to efficiency gains. During quite a bit of that period, we have been running our frac fleets 24 hours a day, and also, to the extent we had a flat rig count, we were able to really wring out efficiencies. And related to that, we have reduced our frac bank something like 40 wells, which added to 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 row-risk basis and on a predictable basis. That is why if you look forward to our planning numbers for production, we think we can meet or 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, put 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 would move to 14 rigs, however, we have dropped two rigs in consideration of low natural gas prices. In fact, of the 125 wells we were going to drill this year, only about 15% will target dry gas. In strategic areas, 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 profit. 45 wells have already been stimulated using white sand, and they look good as compared to their ceramic stimulated offsets, which saves upwards of $700,000 or more on each well. So combining that with vertical integration where we have two 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 gain, too. We added one more CGP, a central gas processing facility, and have two more planned for the mid-part of this year.

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 BOE in the fourth quarter of 2011. And so, as I look forward to this, we think we are on target with this year's guidance. And, as we go forward, our rig count will be increasing is the current plan to 14 in 2013 and upwards of 19 rigs in 2015. And so I think this growth is achievable in 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. They continue 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 four rigs next year. You may recall we held off for the time being moving to four 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. But I think we will probably move to four rigs next year in consideration of the need to preserve leasehold.

And then the result 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 6000 BOE per day, but that will 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 four rigs in 2013.

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

Finally, some positive news we have for you 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 we had a success, was drilled on 100% working basis to Pioneer. If you look at the map on Slide 17 you can see where this well was drilled as designated with the star, and this tested the southern extent of the accumulation. And to the extent it is a very positive well, one of the best wells we've drilled in the Torok making an IP rate of about 2,000 barrels a day. It gives us confidence we have added pretty substantial resources, maybe 50 million barrels of oil. We've produced the well for several days, and we're, of course, forced to move off the ice in the face of the break-up as the weather was warming. But, as Scott mentioned, we probably will look at potentially producing this well next winter and testing it further and 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. We did have some gas in another zone, but gas in this area is basically noncommercial. And 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 is 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.

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 and abandonment for $53 million for the quarter does include the unsuccessful well that Tim talked about in Alaska for $19 million and includes 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 have done to support our growth, and then some restricted stock retention awards that we have done as well as the timing of some charitable donations that were front end loaded in 2012. On current income taxes, the only difference there now being $12 million is we now are projecting to pay some AMT tax in 2012, and that is the reason for the increase.

Turning to slide 19, Price Realization. On the bar charts there, you can see that oil is up 8% from the fourth quarter to $99.15. NGL prices are 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.

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

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

Turning to slide 21 on guidance, production guidance for the second quarter -- 149,000 to 154,000 BOEs per day. So we continue to ramp up on the production side. Exploration and Abandonment of $25 million to $50 million does reflect some carry-over 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 are there for your information. I won't go through you each one individually.

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

Thank you.

(Operator Instructions)

Dave Kistler, Simmons & Company.

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?

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

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 your drilling program next winter -- previously this has been discussed as a potential divestiture candidate. Is that off the table?

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

Okay, appreciate that.

And then, just one, thinking more about the service cost side of things. Obviously, you have vertically integrated both in the Eagle Ford and the Permian. And it feels like there are 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 team's efforts, equipment from the Eagle Ford to the Permian, so you could take advantage of any cost weakness that is taking place in the Eagle Ford versus the Permian?

Hey, Dave, this is Tim.

Let me just say this first of all. We are noticing certain areas, you know -- a little bit of softness when it comes to pumping services. But in general, that's coming off a very high peak. We are basically insulated from that, as you might guess, mostly because, in Eagle Ford Shale, we have two 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 five of our own fleets, going to six here shortly, in the summer -- actually six going to seven, I guess, when you 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 are still making quite a lot of money on the -- 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.

Okay. I appreciate those clarifications. Thanks, guys.

Michael Hall, Robert W. Baird.

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 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 activities? Is there any ability to do that?

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

I'm saying, but even further than current plans?

Our focus right now, obviously, if we continue to make great wells like we have in Giddings, we will continue to -- going into '13, '14, '15, probably look at accelerating the Wolfcamp program. Eventually we need to be going north into Midland County. We need to be drilling some Wolfcamp A zones, C zones, and D zones. So there's probably a good chance, but we need more data points.

And we would like at some point in time to see our oil prices to be able to keep a strong vertical program going. Right now, we're going to 30 rigs starting later in the summer on the vertical program, but we would 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 two. So we would like to be able to move the rig count up on both sides over the next two to three years.

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

No, I think we'll be doing it rateably throughout the year.

Okay.

You can see that we've had a good start on that in the first quarter. I think that will just continue, as we drill with the same number of rigs throughout the entire year. But our frac bank there -- we can easily handle our frac bank there with the three fleets. So it will be very steady as she goes.

Okay. Thank you very much.

Will Green, Stephens

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

Well, if you look at the science wells compared to what we would 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 it would be $700,000 less, especially when we are in development drilling mode. We also do cores in these wells, typically from a science standpoint. That is about $500,000 or so.

We have a micro-seismic typically done, as we're trying to understand how the fracs propagate, and that is about $400,000. We do extra and very significant logging sweeps, which is about another $400,000, compared to what you would do in a development well. So when you're done, that is $2 million which is really not necessary in connection with just normal development drilling.

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

What the split is, is your question?

Yes

Well, so when we are in a let's say $6 million to $7 million well, it will be about a $2 million completion, is the current thinking. The rest of that would be drilling.

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

Over the next two years, there is enough expansions right now with Plains All-American Basin Pipeline, and the Magellan line coming on 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 extended. I think that is the next major thing that you'll see, once that acquisition is completed by Energy Transfer.

So, we still need another 400,000 or 500,000 barrels a day by 2020 to get to 2 million barrels a day. 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. Recent WTI -- West Texas versus Cushing has come back within $3 or $4. We would like to see it get back to, obviously, back to $0.50 to $1. 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.

Just one more note related to that, is on the gas side. You may remember we are expanding our Midkiff-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 are well in advance by any issues on gas by those expansions.

Great. I appreciate all the color.

Jessica Chipman, Tudor, Pickering and Holt

Two questions for me.

The first -- just on the two wells you've drilled so far in the horizontal Wolfcamp. Do you have a preliminary estimate for an oil and gas mix on the EURs of those two wells?

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

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

It's a combination of the frac bank. You remember, the frac bank came down significantly in the first quarter in the Permian Basin. And also we will be ramping up -- I mean ramping down the vertical from 40 to 30 rigs, are the major items of why you're not going to see a big ramp-up second quarter.

Okay. And the back half of the year.

Yes.

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

The Permian Basin, we're at 60 to 70 wells in the frac bank at the end of the quarter; Eagle Ford Shale about 10; Barnett, just at 3 or 4 or 5 wells.

Okay, that is helpful. Thank you.

Leo Mariani, RBC Capital Markets?

A 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 about 4,000 barrels a day.

The Torok well that Tim and I mentioned, Leo, it was suspended. So, it's not producing. But the Nuiqsut well is still producing 4,000. It has been doing it for about two or three weeks. We just need to watch it. Obviously if it does -- If it hangs in there in the 4000 range, or even 3000, we should get a nice bump, obviously, over the next several months.

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

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 wells, essentially if you move due east Giddings and stay south of Midland County, that is how you get to the 400,000 acres. The Giddings well sort of sets that up.

So 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 four boxes on slide number 9. But then -- Giddings, you can see we have a massive amount of acreage around Giddings and back to the east -- that is how you get to the 400,000 -- adds another 200,000 acres.

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?

It's hard to tell. We still have some offers out there. I think a lot of deals over time are going to be farm-outs, and maybe less acreage. I think some people have indicated they want to drill with us, but we don't want to put additional rigs to work; so I think it will probably come -- I don't think we'll do 17,000 acres the 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.

All right, thanks, guys.

Bryan Corales, Howard Weil.

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

Yes, as I have mentioned over the last several weeks, at you all's conference and other people's conferences that, first of all, we need to really prove up. We are excited about the Wolfcamp play. We really need to prove it up. And then we have, obviously, several items access to us, whether it is 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 (technical difficulty) it is going to be a good year before we 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. We're going to evaluate all the opportunities, Brian, [at just one time].

And what is your comfort level? The balance sheet is obviously pretty clean. Is there a certain metric that you look at, whether it is debt to EBITDA, or where the comfort level is for you guys?

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 are at 1 or better. So, we feel like that is a great target to stay within. So, as our cash flow goes above that then we don't mind using some of the balance sheets as long as it stays debt to EBITDA of 1 or less.

Okay. That was very helpful. Thank you.

Amir Arif, Stifel Nicolaus.

A couple of quick questions -- the three horizontal Wolfcamp wells you drilled in Q1, were those also targeting the B bench, or have you started already targeting some of the other benches up there?

Those were all B bench targeted.

And when do you start -- I know you talked about starting to target some of the others -- is that happening 2Q, or is that a '13 event?

I think it's by the end of the year.

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

Yes, it's only 50,000 acres that we have expiring -- so that is 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 of 2013. So the rig count is designed to hold those 50,000 acres. It preserves about 400 drilling locations.

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?

It's probably going to most likely be the -- 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.

Perfect. Thanks.

Sven Del Pozzo, IHS.

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

It's primarily due to our extensive array of log data and core data that we have than most of the peers. We have been in the field for 50 years, and we just have the largest set of data -- that we have done lots of work over the last two or three years. And so we feel like the D and the C is more localized in 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.

And what about silica content?

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

It's in the (inaudible) one.

It's a slide that we show as compared to other shale plays. 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.

Okay. And then 140-acre spacing I have seen for the horizontal Wolfcamp. Is that just including one bench?

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

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

There were coring wells in some of these newer areas to the south, and 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 peter 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 some money on science in the early part of this campaign. Most of the science drilling will be done by the summer.

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?

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

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

Really nothing out of the ordinary. It's just business as usual. And we have been selling to the same markets.

Okay, thanks.

(multiple speakers) 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 a better realization.

Thank you.

Dan Morrison, Global Hunter.

Most of my questions have been answered. Torok in Alaska -- what was the cost on that well?

I think we spent on the two Alaska wells, Dan, we spent a little over $50 million for 100%. We had 100% on both wells.

You said you thought you had several more locations.

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

Okay, great. I think that's it for me. Thanks.

Charles Meade, Johnson Rice.

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

The answer to first question is no -- no effect from any of their issues. Secondly, we're working with a different set of parties in terms of off-take. And actually the big news for us is we'll have our oil on a pipeline mid-part of 2012, as opposed to being trucked today. But we don't have any kind of those infrastructure issues. We're, as you know, Charles, we have a leadership position because we were first mover on all this infrastructure

Great, thank you. Good to hear.

Second question -- this is another horizontal Wolfcamp question. One of your competitors talked about a horizontal Wolfcamp well they drilled in southeast Ector County. So, you know, well to the northwest of the activity you and EOG and everyone else has been targeting. I believe that they said it was in the Odessa South area. And 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.

Yes, that well, I think, was about the first 30 days if I recall the note that I read. Our two Giddings wells are about 50% better than that well on the first 30 days. The rate looks pretty good, but that is pretty much where the Wolfberry play was coined over the past three or four years, on the west side of the [flank]. 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 have been asked -- there are several people drilling wells now in Terry County, way to the north.

So if they find it out in Ector County, and find it out in Terry County, it's going to end up be a 3 million or 4 million-acre play. So it's going to be -- the number is going to be greater than we have seen. So we've just got to wait on results. So you've got Glasscock and people moving east from Glasscock looking for the Wolfcamp, and they are going way north and now they are going west. But we still feel like the center part of the play is, where our acreage is, the best part.

Great, thank you.

Rehan Rashid, FBR.

Any thoughts on what portion of your acreage is exposed to decline?

We have a lot of declining acreage in Glasscock County. I am estimating 100,000 to 150,000 acres. We have a good potential, but right now we show less oil in place on our data points. Still it 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 is where you'll eventually see us do most of our drilling. And that is going to be focused on the A and B. We'll let the other operators prove up Wolfcamp D or decline on the eastern side.

And I am going back to Alaska real quick -- so, is that sometime next year, where we are at a point where we decide to keep Alaska as a long-term core asset or jettison it? Any thoughts on timing to come to that decision?

Yes, you have -- as you notice, the production has been flat or on the 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 it and keep growing it. So that's the key. Do we have enough upside and growth to be able to reinvest the cash flow and grow the assets? And we love growing assets.

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

That is a decision we can make down the road. Yes.

Okay, thank you.

We have that decision on all of our assets.

Brian Singer, Goldman Sachs.

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

Yes, it is mostly up in Reagan County right now. It's obviously to identify faults -- to make sure we stay away from faults, primarily.

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

I think, Brian, I'd just say that, at this point in time, we are in the process of ramping up Barnett with a drilling campaign that is going to increase next year. I really look at it as a fourth leg on the 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 is 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 one of our four growth assets in Texas and I would plan to keep it that way.

Great. And then, lastly -- you touched on this a little bit earlier in terms of the -- potentially 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, six months out? When should we expect that?

I think by the end of the first half of this year, Brian, we will have most of the science wells drilled. We've collected data 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.

Great, thank you.

Dan Morrison, Global Hunter.

Back to the crude oil takeaway issues in the Permian. Have you all got access on the Longhorn system of gaining capacity, or is that pretty much held by marketing companies? (multiple speakers)

Yes, we do have take-away capacity. I don't know if we've disclosed it, have we?

Frank?

No, we haven't.

Yes, we can't disclose it to our agreement with Magellan, but we did take away specific takeaway capacity on that pipeline.

Great, thanks.

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

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

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