先鋒自然資源 (PXD) 2011 Q2 法說會逐字稿

Good day, everyone, and welcome to today's Pioneer Natural Resources second 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, Vice President of Investor Relations. Pioneer has prepared PowerPoint slides to supplement our comments today. These slides can be accessed over the Internet at www.pxd.com Again the Internet site at access the slides related to today's call is www.pxd.com. At the website select "Investors." Then select "Investor Presentation."

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 a number of risks and uncertainties that may cause actual results in future periods to differ materially from the Forward-looking Statements. These risks and uncertainties are described in Pioneer's news release, on page 2 of the slide presentation, and in Pioneer's public filings with the Securities and Exchange Commission. As a reminder, today's conference is being recorded. And it is time for a few remarks and introductions. I would like to turn the conference over to Pioneer's 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 is going to be up first; he will provide the financial and operating highlights for the second quarter of 2011. He will then update you on the Company 's production outlook, capital program and cash flow forecast for 2011 through 2014. After Scott concludes his remarks, Tim is going to discuss our drilling results and plans for the Spraberry, Eagle Ford Shale, and the Barnett Combo Play. In addition, he will summarize the significant benefits that Pioneer is generating from our vertical integration investments. After that, Rich will cover the second quarter financial highlights in more detail, and then he will provide earnings guidance for the third quarter. And after he completes that exercise, we'll go through your questions and open up the line accordingly. With that, I will turn the call over to Scott.

Thanks, Frank. Good morning. We are going to start out on slide three, the highlights. Pioneer had another tremendous quarter with adjusted income of $115 million or $0.94 per diluted share, significantly above the consensus on the street. Excludes losses from discontinued operations of $2 million or just $0.01 a share and excludes our mark-to-market gain, derivatives of $133 million or about $1.10 per share.

In regard to productions, we are above midpoint at 119,000 barrels of oil equivalent per day. If it wasn't for the loss of 2000 barrels a day, which we lost, essentially, all during the quarter in the Spraberry asset team, we would have been at the high end of guidance. That 2000 barrels a day was primarily lost due to the fact that a large Permian producer with trucks called us up and had to move the trucks out to pick up their own crude. So it took us really about three months to bring the trucking fleet back up, find some other trucks, and pick up that crude. What is interesting that this Spraberry division is already up between 45,000 and 46,000, so it is significantly up, and that's per-day equivalent with the first quarter average of 41,000.

In addition, I've seen a couple interesting comments from some analysts that Spraberry is still an execution story for Pioneer after being there about 30, 35 years. But if you go back on slide 30 in the back, just the last 12 months, we are up 28% production growth from 31,000 to 40,000 barrels a day. And if you add back the 2000 barrels a day for the quarter, it would've been up 34% production growth just over the last 12 months. It is basically -- we are still not up to full ramp of, which will be by adding another 10 rigs by the end of 2011.

Production for the entire Company was up 7% for the first quarter of 2011 primarily related to the growth in Spraberry, Eagle Ford, and the Barnett Shale Combo play. We expect second-half production of 10,000 barrels a day per quarter approximately both in the third and fourth quarter, essentially all coming from the three areas so we are essentially getting to full ramp-up in Spraberry, getting close to our 45 rig count. Eagle Ford is going well, and also the Barnett Shale Combo.

If you look back on slide 30, the rest of our assets are pretty much exhibiting fairly flat production growth, which obviously, with our long reserve life, flat production on our other assets, spending minimal capital allows us to have this type of significant growth. Our liquids-rich drilling programs, obviously, we are ramping up in our core growth assets. We will be going up to 45 rigs earlier than anticipated. We will be starting them late third quarter going into the fourth quarter. Our results, what's interesting from our Strawn Atoka Mississippian is getting better and better as we see. The potential to increase our EURs in the Spraberry up to 110,000 barrels of oil equivalent just from a combination of these zones.

Eagle Ford is ramping up as expected. The Barnett Shale Combo program, we are starting to see several wells over the last few weeks exhibiting much better performance than our type curve. Increasing 2012 production growth target from 18% plus to 20% percent plus with additional 200 million, and that will explain that, but that's primarily the additional rigs going deeper, but it's pretty much all attributed to the growth in Spraberry which Tim will talk about. We are not including in those numbers results from the Atoka, the Mississippian, or the horizontal wells in that increase at this point time.

We extended our compounded annual growth rate of 18% plus through 2014. In addition, Tim is going to go over some great detail our investment of about $440 million over the last two years into the service side on how much we are saving. Our savings will exceed over $450 million by year end 2011. We'll continue to increase significantly with our vertical integration. A lot of it is coming from the hydraulic horsepower that we have added.

In fact, we've added another -- we made a decision to add more fleets, primarily going under the Spraberry and primarily Eagle Ford. We are adding another $100 million this year. We are starting to get feedback, but this equipment will probably come on by next summer in these areas and will save us on lot of higher third-party charges. In addition, we are starting to hear feedback that it is going to be a two year lag time. There's so much equipment that is being added to shale plays around the world. Most of it has to be sourced in both Canada and the US market. So we are now back -- people want new equipment. It's going to take two years to get it. So we are set up to execute our growth based on the amount of equipment that we have ordered. So this equipment will be coming in next summer.

In addition, we've added some significant derivative positions on oil, and before the recent fall about 2 to 3 weeks ago, we are up to 50% hedging. If you look back in our schedule, up to 50% oil hedged in 2013 and 25% in 2014. Pretty much did three-way collars between 65 and 90. We did $90, and then we let it flow between 90 and 130, and after 130, we give it away. So significant collars help the oil side of the business at it is growing, up to 60% over the next several years.

Going to slide number four, in regard to our production growth, as I mentioned already, 2012 has increased primarily all due to the Spraberry trend area growth increasing. A lot of that is coming from the Strawn and also coming from the increased rig count. We extended the annual production growth target through 2014 and our liquid production increasing up to 60% in 2014. We are maintaining our guidance range of 125,000 to 130,000 barrels a day for the year. We expect to be at the lower end primarily due to the severe weather we announced in first quarter, and some unplanned third-party impacts which you can see in a footnote that have already happened in the first and second quarter of 2011.

Going to slide number five, our capital budget changes. We are increasing the drilling budget, again, as I have mentioned, from $1.6 billion to $1.8 billion. It's primarily due to the Spraberry deeper drilling and the success we are seeing there. In addition to the six horizontal wells that we are drilling now, the first four are in the Tippett Shale zone and with recent EOG announcement of their 600 barrel A plus well and the approach well is the reason we have targeted the Tippett Shale down to the South portion of our acreage with the next four wells. Tim will talk more about that.

Increasing these ten rigs a little bit earlier, about $50 million. Obviously, with the delay of our Company-owned frac equipment, we had to go out and hire some third-party fracture stimulation services. That was an increase. But what is interesting, in our entire budget, we are only seeing about -- when you look at strictly just cost creep, we are only seen about a $50 million increase, about 3% of our total budget, due to the service cost and pricing power. That reflects tremendous investment of $440 million that we made over the last two years, primarily into fracture stimulation.

I've talked about the fleet that will be coming on, the two fleets that will be coming on by mid-next year already. Obviously, the benefits from increased capital spending allows us to increase our production growth target, again, primarily from the Spraberry trend area field, as you can see, upping those numbers from 52,000-56,000 to 54,000-59,000 barrels a day next year, and also the results from the Strawn production. Again, as I mentioned, we are in our -- increase in production we are not adding at this time results from the Atoka, the Mississippian, and the six horizontal wells that we see.

Again, vertical integration, obviously this equipment that we will be adding essentially is going to be saving us about $80 million year, so probably about a year payout, around a year payout in this equipment.

Going in to slide number six, our operating cash flow. Again, we see operating cash flow of about $1.5 billion, and using about $600 million of Tunisia sale proceeds. That will leave us about $200 million of Tunisia sale proceeds which we'll be using to fund, in addition to the cash flow next year for the 2012 CapEx.

Looking at slide number seven, you can see the significant ramp up in cash flow based on the recent strip, going from $1.5 billion up to $3.1 billion. We will be doubling over the next four years, 30% compounded growth rate from 2010 to 2014. 2012, with the CapEx, is expected to be roughly $2.2 billion. We will be spending the $200 million of Tunisia proceeds and the $2 billion of cash flow. Going into 2013 in 2014, we'll be essentially spending -- the CapEx will be about the numbers that we see in our cash flow.

Investment highlights, again, Pioneer with over 20,000 liquids-rich drilling locations in three key areas, the acceleration in the our Spraberry and Eagle Ford area starting to perform as we have seen Spraberry grow significantly over the last 12 months. Eagle Ford just now taking off again. The Tunisia sale, tremendous opportunity for us, allows us to be able to accelerate over the last few months, again, having one of the highest compounded annual growth rates for the top 10 independents in the US, and also with cash flows growth of 30% plus.

Vertical integration has been a much better benefit than we ever imagined. The decisions we made back in 2009 to buy into those businesses, were are seeing tremendous returns. It allows us to keep CapEx down significantly over the next several years.

In addition, lastly, the strong balance sheet of debt to book of about 31%. Let me turn it over to Tim to get into the assets.

Thanks, Scott. I will start you on slide nine where I'll be giving you an update on the Spraberry trend area, where as many people know, we are really the dominant player. And we are the largest driller, the largest acreage holder, and the largest producer, which also makes us one of the largest drillers in the Permian Basin. What's happening in this field, of course, is we are the dominant player, but it is a big field which is continuing to get bigger as a result of all of our activities. And as you turn to slide 10, a key reason for that is our continuing program of well deepenings. And as we continue to program, it gives us confidence that we will have the opportunity to add significant additional EURs to future wells.

The table we show below gives a little bit of detail on the data that we are collecting from these well deepenings, and we are finding very significant positive results. So for instance, we already drilled 85 Strawn wells. The number shown to the right showed the cost of those wells and peak rates as well as potential EUR. In the case of the Strawn, it's something like 20,000 to 40,000 BOE and it's prospective at about 40% of our acreage. And about 25% of the wells we are drilling this year have a completion in the Strawn. And what we are doing, of course, in this case, is we are beginning the process of immediately co-mingling the Strawn with the upper zones because we haven't updated at this point with the Strawn wells we drilled to understand exactly what their contribution is.

New data coming in, though on the Atoka and Mississippian is shown in the next couple of lines. We've now completed two wells in the Atoka. There's significant cost range shown there, and the way to explain that is, if we are at the top end of the range, say $750,000, that's in areas where we would be drilling deeper to the Atoka, and in that case, we need an intermediate string of casing to be added, and in a lot of cases, we have to use CO2 frac. The lower end the range, which would be about 50% of the wells, we can deepen the well to the Atoka for something like $250,000. That's where we do not need that intermediate string of casing and where we can use water fracs. In any case, what you see about the Atoka is a significant contribution of 50,000 BOE to 70,000 BOE and it's prospective. And it's somewhere in the neighborhood of one quarter to half of our acreage.

The Mississippian, we've just completed our first well in the Mississippian. It's a zone, which is currently testing -- currently IP at 105,000 BOE per day, and we think the Mississippian can contribute 15,000 to 30,000 BOE where it works, relatively lower percentage of our acreage to the North something like 10% to 20%.

I've circled the Strawn and Atoka top end of the ranges, to focus on the fact in the areas where we have Strawn and Atoka, we have the possibility to add up another 110,000 BOEs to our EURs from that deeper drilling. Realizing in the most of the central areas of our acreage, the Strawn and Atoka are present, while the Mississippian generally is present to the North. In general, we would say you'd not have both Atoka and Mississippian present at the same time. So you can not add this table up. It just depends on where you're drilling.

But as you can see in the green circle I've shown, a substantial potential for additions of EUR. And the drilling continues. We will be testing several more Atoka wells this year. And then after testing those wells, we will co-mingle them with the upper zones. In the case of the Mississippian, 10 more wells to be drilled this year, a total of 24, as we continue the process of testing the play.

So the deepenings are an important contributor I think to future EUR adds and production adds in this field, as we learn more. We have a substantial amount of offset data from other operators as to what these Atoka and Mississippian wells have done in the area. That's why we have a lot of confidence in their ability to also add a pretty significant EUR.

Going to slide 11, on the horizontal program, as we have already discussed before, we've drilled two wells, the second of which was drilled in the lower Wolfcamp. That was the well we discussed last quarter, that at that time, only had a few days of production. We ultimately IP'd that well at about 220 BOE per day. We are continuing, as Scott has already discussed, a substantial horizontal program with one rig, six total wells by the end of year, the first four in the middle Wolfcamp Tippet Shale that Scott mentioned, and a couple more in the Jo Mill, which is a middle Spraberry section. So we are going to continue this program through the rest of this year. The first of those wells is actually drilling. It's going to have a 6,000-foot lateral, 30 stage completion. So we'll continue to watch results from the R&D program to determine if there are horizontal drilling applications that can enhance the already excellent economics of our extensive vertical well program.

Okay, turning to slide 12. As for production, it's really all about putting wells on production, and we discussed that in the last quarterly call. We accomplished our goal in the second quarter; we put 146 wells on production. And you can see in the slide we've got a substantial amount of wells to be put on production, significantly higher in the third quarter and the fourth quarter, and that gives us confidence in our production forecast.

We will be adding the seventh frac fleet in the Permian Basin in the fourth quarter. That's a Pioneer-owned fleet, and that puts us back to our stated goal of being somewhere in the neighborhood of two thirds vertically integrated when it comes to pumping services in our key areas. As to the rig count, Scott has already alluded to the fact that we will be bringing in the rigs earlier than anticipated.

All of our prior guidance had 45 rigs beginning January 1. We're bringing them in something in the neighborhood of a quarter earlier than planned. Of course, as we drill the wells during the fourth quarter with the additional rigs, it will have very minimal impact to 2011 production because of the time it takes to put the wells on production. However, it's going to have a big positive effect on 2012 production, and that's shown in more detail on slide 13.

Scott has already alluded to the fact that the truck fleet issues were pretty significant during the second quarter. That was both with regard to shortages of crude oil hauling trucks as well -- and really to a lesser extent, water hauling, that led to about a 2,000 barrel a day shut ins or inventory builds as we were waiting on trucks. But as has been the case with all of our vertical integration initiatives, we are tackling that problem, and I think we have it solved. And the way we are going to do that is to on the one hand, add our own water-hauling trucks, and then we are adding a significant number of third-party oil trucks as well as new pipeline installations that will then relieve the need for more trucks.

And in fact, if you look at the truck count, this is the oil-hauling truck count in June that were working on Pioneer wells, we had about 22 trucks hauling oil for us. We've now increased that to 35 by September, or a 60% increase, and we believe, essentially by virtue of the actions we've taken, we've relieved this issue as of this month. We also have several more trucks under contract for next year, several thousand barrels a day, somewhere in the neighborhood of 5,000 to 8,000 barrels a day of new gathering pipelines next year, and all of this will serve to reduce pressure on the need for crude oil hauling trucks.

Current production, Scott said this earlier, but it's about 46,000 barrels a day in the Spraberry trend area for us. That gives us pretty good confidence that our third-quarter number looks good. If you take a look at the increment in 2012, by adding the rigs earlier in 2011 it's pretty substantial. So the 2012 guidance we had last quarter for Permian was 52,000 BOE to 56,000 BOE per day. By adding those 10 rigs earlier, we can jump that to 54,000 barrels to 59,000 barrels a day, which has a big impact in terms of increasing the overall Company rate of growth to 20% plus for 2012. Our average well cost for this year is still in the neighborhood of $1.5 million, $1.55 million, still very strong rates of return, and it has a lot to do with our vertical integration that I will talk more about in a minute.

I will wind up the discussions on Permian in discussing our 20-acre program. We've drilled 24 wells since 2010 with very good results, encouraging results that indicate that the wells are generating EURs above our old, traditional 110,000 BOE type curve, and we'll be drilling another 10 to 20 by year end. But the 20-acre drilling, by virtue of deepening these particularly into the Wolfcamp, are basically offsetting depletion effects by down spacing.

In the waterflood, we've seen continual increases in the number of wells that are actually increasing oil production as the result of the effects of water injection, and the overall curve is flattening when it would otherwise be on a significant decline. That's indicative of the zone that is under waterflood, the upper Spraberry zone, substantially increasing production. And I think shortly, we'll be giving you some information exactly how much we think it is increasing. But very positive result so far on the waterflood.

Okay turning to Eagle Ford Shale, that's slide 14, the Eagle Ford Shale assets are hitting their stride. As planned, we're running 12 rigs. The average lateral length of the wells is now up to about 5,500 feet. The economics are quite outstanding, as we've always discussed, owing to the rich condensate and generally liquid-rich nature of these wells. Well performance looks very good. We're seeing very good performance in DeWitt County, offsetting Black Hawk.

One thing we are doing, as we discussed on the last call, is to push the envelope with regard to the use of white sand as a proppant. We've already simulated 10 wells, and the performance of the wells look very good and very similar to the direct offset wells where we used ceramics for the proppant. So the idea this year is about 30% of our wells this year will be using white sand, and that's the number also planned for next year, 2012, about 30% of the wells. And importantly, that reduces the cost of the wells something like $700,000 per well, which is very significant if you look at the future drilling campaign.

Infrastructure build-out continues. We now have six of our central gas processing facilities completed. A seventh will be completed by the end of this quarter and an eighth next quarter. So we are really ahead of the game when it comes to build out of infrastructure. And the result, as you see on slide 15, is the ability to put more wells on production. We've met our goal in the second quarter of putting wells on production in the Eagle Ford. We put 18 wells on production. That's reflecting the frac bank being significantly reduced as well. The frac bank starting the second quarter was 22 or 23 wells, and now it is 11 at the end of the second quarter, which is basically our minimum run rate which is basically one well per rig. But you can see as we bring the two new CGPs online this quarter, we have a substantial ability to add a lot more wells to production, and in addition to that, we will see a similar ability to do that as we get into the fourth quarter.

Though this area is going to be ramping up dramatically as shown on slide 16. With the put-on-production well count Increasing third quarter, you should see a significant increase as shown on the slide up to 14,000 to 17,000 BOE per day. And as you look forward, of course, in the next several years, this is an area of continued drilling, substantial acceleration of the rig count, You can see we are going to 14 rigs next year. Those 14 rigs are all under contract. And then 16 rigs and 19 rigs looking forward.

On slide 17, the Barnett Shale Combo play continues to show excellent results, and in fact, better results as time has gone on. We have -- now in the process of actually acquiring new 3-D seismic to optimize our drilling locations. We still have the two rigs running, and we anticipate going to four rigs next year.

Importantly, also, we've added our own Company-owned frac fleet during the second quarter, again, getting to where we were heavily dependent on Pioneer frac fleets as opposed to necessarily going outside. And the reason for that, I will show you in a couple slides as to the cost savings related to Pioneer services and Pioneer pumping.

The results in Barnett, though, are going to be increasing as well, as shown on slide 18, as we begin the process of getting more wells on production. That is something in the neighborhood of 4,000 BOE to 6,000 BOE per day this quarter, and growing as we increase the rig count in the next several years to four rigs at a minimum.

Okay, as to slide 19, this is some data to give you some views as to what our total fleet capacity is today. In fact, we have six frac fleets working in our three key areas today, going to eight by the end of the year. That will result in, as Scott has already mentioned, about $440 million cumulative investment, and will generate the ability for us to have 225,000 horsepower.

You can see the photo of Pioneer Green. This is what we see all over our area is Pioneer Green, and we are proud of all the people who work in that group. And according to third-party analyst reports, that makes Pioneer the number 15 Company among all North American pumping services companies in terms of horsepower.

And slide 20 kind of gives the bottom-line on this vertical integration. This is the first time we've disclosed this information in this kind of detail. But the way you can read this is, the number of frac fleets working in each area, and then the number by the end of the year. What I am going to be talking about is end-of-year run rates because we will incorporate the fact that we have two more frac fleets coming in this year.

You can see the savings per well, very substantial, for instance, you save $1.7 million on Eagle Ford wells by fracking our own wells. Now, the important note to be made there is, where we are comparing the cost of Pioneer pumping the well versus an outside party is related to longer-term third-party contract rates, these are not spot rates, which are dramatically higher.

But if we simply compare it to longer-term contract rates for pumping services, we can see that we generate substantial savings in the neighborhood of $460 million on an annual run rate basis. And so what that means is, as for all this investment, we'll have payment in less than one year, as compared to doing third-party, longer-term arrangements. As I mentioned, if we were to use spot rates, they would be substantially higher, and in fact, if we use current spot rates across the board for these three areas, our current savings run rate would be $715 million, seven months payout. So you can see the benefits of this are really coming into roost, and I think they will continue as long as we are in a tight pumping services market. So with that, I will pass it over to Rich for his discussion on the second-quarter financials and third-quarter outlook.

Thanks, Tim. I'm going to start on slide 21. As Scott mentioned before, net income attributable to common stockholders was $246 million or $2.03 per diluted share. That did include unrealized mark-to-market derivative gains of $133 million after-tax, or $1.10 per diluted share, and a loss on discontinued operations related to our Tunisia post closing adjustments of $2 million, or $0.01. So adjusting for those two items, income was $115 million or $0.94 per diluted share.

Looking at the bottom of the slide where we show our results compared to our guidance we came out in the second quarter, you'll see that each of the items came within guidance or on the positive side of guidance, with the exception of current taxes, which were slightly higher because of South Africa taxes be a little bit higher than we anticipated as we came into the quarter.

Turning to slide 22, talks about price realizations. At the top there, you can see our realized prices, which exclude any impact from volumetric production payments or derivatives. You can see that oil prices were up to $98.50, or 10%, relative to the first quarter. NGL prices were up 14% to $48.16 in the second quarter as compared to the first quarter, and then gas prices were up 4% to $4.31. So commodity prices helped the Company, improved our margins during the second quarter.

On the bottom of this slide, you can see the impact of volumetric production payments and derivatives and how those affected our overall realizations. So that's there for your information.

Probably a couple things worth noting, the volumetric production payments, as many of you recall, end at the end of 2012, so we will pick us an extra 4,000 barrels a day of production when those run off. And then the derivatives included in our price impacts for oil run off at the end of this year, and then, that will be the end of those.

Turning to slide 23, talk about production costs. For the second quarter they were $12.82, down 4%, from the first quarter. I think the important thing here is if you look at the red part of those bars and base LOE for the past five quarters, if you adjust the fourth quarter to reflect the processing fee recovery we had, we are basically in the $7.70 to $7.90 range for the past fiver quarters. So I think that's a real tribute to our asset teams. They've done a great job managing our costs, especially in an inflationary environment with the run-up in oil prices.

Turning to slide 24 and looking at third-quarter guidance, production guidance for the third quarter is 125,000 to 131,000 BOEs per day. That range includes an estimated four weeks of lost South Africa production due to our wells being shut in currently as a result of unplanned outages at the GTL plant that takes our production. Current expectations are that the third-party operator will be able to get the plant back online sooner, but if the outage does extend beyond four weeks, we could have to update our guidance later in the quarter.

If you look at the rest of the items on this page, you will see that they are very similar to what we've had in past quarters and as our historical results have come in, so I'm not going to go through each one individually, but they are there for your modeling purposes. So why don't I stop there, and we'll go ahead and open up the call for questions.

(Operator Instructions). And let's first go to Dave Kistler with Simmons and Company.

Morning, guys.

Good morning.

Real quickly on the services side of things with the margins you guys are putting up, do you think about at some point spinning a piece of that off or monetizing a piece and putting that potential capital towards accelerating your drilling program even further?

Not at this point. Tim threw out a $715 million number. I guess if somebody offered $3.5 billion, we would have to strongly consider it. 5 times that $715 million number. But right now, with the savings that we have and the growth in it, and the benefits we are seeing, we just don't see it. So --

Furthermore, Dave, we are still growing that asset base, right? We've got more fleets coming in, so we haven't built what we are going to finally own.

Does that, though, become ultimately an option for the business? Or is this something you think you will always want to have tucked underneath?

We think, with 20,000 locations -- and we are strong believers in the oil environment over the next several years -- that we just see -- and the tightness of the hydraulic horsepower, as I mentioned right now, it's going to take 2 years to get new equipment. We just see it tight for several years, and the demand for the international shale plays that they are developing now, that's all coming out of the US market, too, so it's going to be tight for a long time.

Okay. And, maybe following up on that a little bit, in terms of -- you are showing very attractive production growth, so don't take this as something suggesting your growth isn't attractive, but when you start looking at production from South Africa and Alaska, and your growth continues, this becomes a smaller and smaller piece of the equation. Do you look at those as vehicles to monetize and potentially make sure you can continue to live within cash flow and deliver the same kind of or better growth than you are already throwing out there?

Yes, right now South Africa, our contract runs out in late 2013, so the asset at this point in time in our modeling essentially goes away at that point in time. We do have a upside for extending that contract. So there is a lot of reserves left in the ground, up to 2020, and we can produce it, so it's always a possibility. So at this point in time, we are only modeling to about September 2013.

And then in regard to Alaska, we are drilling 2 key wells, very important wells this coming winter. One's a deep test in the main producing zone out of Prudhoe Bay -- the Ivishak. And then another well is -- we're going to fracture stimulate this new Torok zone that we drilled 2 wells they have been fairly good over the last 12 months. But we have not selectively fracked each zone like we do a plug and perf like in Eagle Ford or in the Spraberry horizontals. We are actually going to do that technique up there, get a much bigger frac, and we think the wells will come in much stronger.

So those are really 2 key wells. And then, hopefully, with that success, it will drive growth over several years. But it's always an option, in regard to whether or not to look at divesting of those 2 assets. But right now we see 1 running out and 1 growing significantly over the next several years.

I appreciate that color. 1 last, probably a little bit more micro question. When you look at the Atoka interval that you guys are exploring or developing at this point, the cost metrics on that went down on the low end. Can you talk a little bit about what drove that?

Tim?

I think I mentioned this during the call. We have now determined that some of areas where we have Atoka prospectivity are shallower, and in that case where it is shallower, we do not need that string of casing -- intermediate string of casing that would be needed for deeper drilling. Some of the areas of the Atoka, you have a pretty clay-rich section where you worry about swelling, where we have to do CO2 fracs. In other areas we don't see as much clay content. And in that case, we can use water-based fracs, which are cheaper. So what you are seeing in the low end is those areas that are shallower, and as a result, are cheaper to complete. And that said, I think 50% of the acreage probably lies in each of those categories.

Great. I appreciate the additional color there, guys. Thank you.

You're welcome.

And from Goldman Sachs let's go to Brian Singer.

Good morning.

Hi, Brian.

Looking at the various guidance for 2012, it would seem like if we used a midpoint for at the Spraberry, Barnett Combo, and Eagle Ford, and some normal course decline rate for some of the assets you may be a little bit less focused on, it would imply greater than 20% year-on-year increase. And I just wanted to see if there was anything specific in terms of more extensive declines or whether you were factoring any asset sales into 2012?

No. First of all, we are using a plus number, 20%, and we are trying to be conservative, as you can see what happened to us first quarter, the winter was much more severe weather. So you have no idea when you're going to have a severe weather or any other type of issue, so we try to, each year, come out with conservative members. But we are using a 20% plus number. I hope it is a lot better than 20%, but as you know, as we've seen what's happened with unplanned outages, in Alaska, with third-party delivery of water up there, with severe weather we had first quarter, it's always nice to be conservative.

Great, thanks. And then, shifting to the Eagle Ford, can you just add a little bit more color on well performance and decline rates, how that is coming in relative to your type curve and the oil, gas and NGL mix that you're seeing relative to your expectations?

Yes, it really hasn't changed. We've been using 6 BCF equivalent. I know we got several questions once Petrohawk increased their reserves, but obviously, it's nice to see people paying 23,000 per acre right next to our acreage and what happened with the recent BHP transaction to highlight the value of our acreage. But we really haven't seen any changes with our original numbers that we came out probably 18 months ago, Brian, so still, we're focused pretty much on the liquids -- more the higher condensate than the lean. But most of the rigs now are focused on holding leases, and then we will -- I think beginning in about 2014, we'll focus primarily almost -- assuming the ratios are still 20 to 25 to 1, we will focus more on the higher rich condensate areas. So we really just haven't seen any change than we really originally come out with.

Great, thank you very much.

Leo Mariani with RBC Capital Markets.

Hi, guys. I was hoping you guys could just talk about infrastructure in the Eagle Ford and your crude oil transportation scenarios which you guys currently do. Are you seeing any bottlenecks? Are you having to choke back your wells at all? And where are you guys selling your crude, and how is pricing working?

Yes, Leo, I think at this point in time I'd say we do not have any significant infrastructure issues in the Eagle Ford Shale when it comes to crude oil. All that oil, of course, is being trucked. Since we were one of the early guys in there, and in doing so we were working on infrastructure before anyone else, we have all the trucks in hand that we need to move oil. So it's really not an issue. The discount for this type of material, though, is related to the fact it is so high gravity, so we tend to get $4 or $5 off WTI for the condensate just because of its gravity.

Okay, and are you guys sending out to be Cushing market? Are you able to get that to any of the Gulf Coast markets?

We are working on the possibility to do some barging with some of the other players who are putting that in place. But for right now at least, it's all WTI-based.

Got you. And what are your current well costs looking like in the Eagle Ford right now?

The blended well costs are still the neighborhood of $7 million to $8 million. That said, as I mentioned earlier when we were talking about the vertical integration business, we can drop those costs by, I think it was $1.7 million. And so our internal numbers are a lot lower than this average, but this also incorporates the fact that we have an outside frac fleet working for us as well at a higher rate.

Got you. So if I was to do some quick math, that would seem to imply that maybe your internal well cost was sort of in that $0.5 million range. And maybe high sixes in external or low eights. Is that about right?

Exactly right. You're good at math.

And can you guys give us a little bit more color about Alaska? The production has kind of stagnated there the past couple quarters. I know you did have some downtime related to some maintenance and some water handling. Is that production expected to start to pick up here in the second half of the year? Just any color you have there would be great.

Well, I was just going to get a little more color on the details on it. But the main issue we've been facing there, Leo, is related to water injection shortages. And this is, as you know, we take water from the other big operators up there, and we have contractual rights to do so, but because of issues they have had from their infrastructure side, we have been severely limited on water injection. And every well in Alaska has water injection paired with it. So to give you an example, we, at this rate, need something like 15,700 barrels a day of water, and we are significantly short of that in terms of what we are being supplied, something like 6,000 barrels a day. So cumulatively what happens is, we don't have enough water to inject. You're basically not properly sweeping the oil from the reservoir, and that's definitely what we are facing here.

We are working on internal fixes to start generating our own water supply. We didn't think in advance of this project that was going to be required because the operator in question we thought could deliver all the water we needed. We are simply finding that that's not the case. So our production would be higher in this year, other than for the fact we are losing production related to this lack of water. Probably 1,000 barrels a day at least in the first half of the year.

Okay. So in terms of you guys obviously working on some solutions, is that something we should expect by early next year? Hopefully something is in place and the volumes start moving up, how should we think about the production progression here?

We are going to be drilling more wells as we speak. But I think our internal solution will not be able to get done until the latter part of next year.

All right, thanks, guys.

You're welcome.

Up next, let's go to Rehan Rashid with FBR and Company.

Morning. A quick 2 questions. 1 on Eagle Ford, the well cost, the $7 million $8 million, does that include or exclude the benefit from using white sand?

Yes, that's a ceramic-based cost, Rehan. So it does not include the benefits of white sand.

Perfect. On your reserve booking for year-end, how do you expect all your PUDs to play out given the success in Strawn and Atoka? Will you be able to incorporate this this year?

Yes, we see similar results to what we showed last year basically in our key areas, Barnett Combo, Spraberry, and Eagle Ford, based on our drilling activity. So it will take us probably, generally, the Strawn, we've got about 8 months of history now, so we will see more bookings from the Strawn. Probably not going to see a lot from Mississippian and Atoka yet.

Got it. Okay. Barnett Shale Combo, well performance improving, could you give us some color on that? And also the Spraberry Shale wells, Wolfcamp, and both carbonate and shale, results are okay so far? Maybe some color on that as well? That should be it. Thank you.

Yes, Barnett Shale Combo wells, they are averaging about 350 barrels a day. So it's about 30%, 40% higher than our type curve, our last few wells, so very, very positive there. So we're starting to see production ramp up fairly significantly in Barnett Combo play.

You said the Spraberry Shale wells. I'm not sure -- we're still opening up all these shale zones in the Spraberry and the Wolfcamp intervals. So obviously, we are seeing -- I don't know if Tim mentioned on the 20-acre drilling, too, we are still -- we are starting to see a lot of these 20-acre wells creep up toward the 140,000 barrels of oil equivalent. If you recall, the offset 40 only opened up the conventional reservoirs that we drilled over the last 20, 30 years. And so we've done several wells and they are holding -- I think we made a statement they're going above 110, but they are getting closer to the 140,000. So a very, very positive result opening up another 15,000 to 20,000 locations for us over the next several years, too. So, I don't -- I'm not sure what you refer to about the Spraberry Shale wells.

Just the initial, the horizontal wells, basically, that are coming.

Oh, the horizontal wells. Tim mentioned the lower -- we're the only ones that have drilled in the bottom of the Wolfcamp. And that's the well but got up to about 220 barrels a day. And we have moved the next 4 wells to the Tippett Shale, which is a middle Wolfcamp zone, and so far we are monitoring EOGs best wells over 600 barrels a day equivalent. Very, very economical, and then Approach just announced in the last -- yesterday, a well over 600 barrels a day equivalent.

And our 4 wells are down in the southern part of the Spraberry trend area, very close to these wells. And that's where the acreage that several companies, including Petrohawk and Forest and ConocoPhillips. And there is a lease sale coming up in September, and essentially all university land has been put up in this area by some operators. So it'd be interesting to watch this lease sale coming up next September out in Midland, but the focus is on this Tippett Shale zone. So we are still encouraged, but we will see after these next 4 wells.

Thank you.

Let's go to Brian Corales with Howard Weil.

Good morning, guys. Just on the Spraberry, when you all drill, do you all go all the way to the Mississippian in most wells and see if it's there? Or how do you all progress on the drilling plan there?

Yes. We've got -- a lot of offset producers going to the Mississippian. Some have gone to the Atoka. Some have gone to the Strawn. We pretty much have it mapped. And what we've been doing on the Strawn is basically we take about -- it doesn't cost very much at all. We take about half our wells down to the Strawn. We've been completing about half of those wells. So if it has porosity, then we will go ahead and complete. So it only takes us another maybe $20,000 to drill and take a peek, so it is insignificant.

In the Atoka, we know exactly which area we are going to take the Atoka wells. We've only done 2 wells. We are 2 for 2 in the Atoka, and we are 1 for 1 in the Mississippian. So same approach. And where it overlaps, where it overlaps in the Mississippian, if there is a Strawn, we will produce the Mississippian for a while, come back up, test the Strawn, and then we'll add the rest of the Wolfcamp, Spraberry zones over time.

Okay, okay. And switching over to the Eagle Ford, with all the -- looks like the infrastructure and you've got the completion crews locked in. What's the major risk, or is there a risk to the outline that you all put together over the next couple of years?

We tried to minimize -- I've always said commodity prices, but we are pretty much protected over the next 2 or 3 years. We have $80 floors and $90 floors over the next 3 years, '12, '13 and '14, on the crude side. We feel like we protected that. Tim and his team have done a -- Bill Hannes --have done a great job in Eagle Ford with all of our major agreements with DCP, Enterprise and Copano. Everybody is cooperating. We're able to execute on getting our product to market.

So at the Eagle Ford, then with our second frac crew coming in, and with the additional frac crews coming in in 2012 and '13, which we can shift to Eagle Ford in '13, is that we essentially have everything taken care of in Eagle Ford.

Okay, guys, thanks.

At Wells Fargo, let's go to Michael Hall.

Thanks. Good morning. Most of mine have been answered. Just a couple quick ones. First in the Permian, on the Spraberry, you are talking 25% of wells being co-mingled this year into the Atoka. Any initial thoughts on what that looks like in 2012? And then maybe what percentage are also then possibly co-mingled to the deeper intervals as well in 2012?

I think you can probably look at it, in the case of the Atoka, about 25% to 50% of our acreage is prospective, so I would say that it will take up a substantial amount of our campaign as we continue to drill that out. But the total number of wells that we have planned this year is 10 more, and we'll probably drill at least double that next year. So it hasn't really been developed in the level of detail yet, Michael, as to the exact drilling plan for Atoka, we are really sort of drilling these first campaigns to know the answer that question.

Got you. And then, can you remind me on gas take away capacity in the Permian, are there any infrastructure constraints there? Like the Midkiff/Benedum plant. Is that full? To what extent do you have priority on that plant, and are you flaring any meaningful amounts of gas? Or how is that?

I think, the situation for us is that we have equity ownership in gas processing facilities. And we've built, recently, a new plant in the Permian Basin that came on earlier this year. And we also are going to be re-establishing the processing from the plant that it replaced, so we will be really significantly increasing our capacity, so actually gas processing capacity is simply not an issue. We also have ownership of another plant to the North that is expanding. So what's happening is the gas processing facilities are being expanded in advance of the increase in production.

Okay. And as you have equity ownership, do you typically have priority on those systems?

Absolutely, and it also has to do with the fact that we have priority in getting our gas gathered as well because that is where the agreements line out. The processors in this case gather the gas, and so we our first priority in every way.

Great. Makes sense. And last 1 for me. Any, by chance -- willing to throw out any run rate in terms of, call it July, or current production after the trucking constraints have been alleviated?

I already gave a run rate on the Spraberry. It's been averaging -- as I mentioned, it averaged 41,000 for the quarter. It's already been averaging 45,000 to 46,000, so we're already up 4,000 to 5,000 barrels a day, Spraberry.

Great. I appreciate that. Sorry I missed it earlier. Appreciate it, guys.

And our next question is from Gil Yang with Bank of America Merrill Lynch.

On the Spraberry truck hauling issues, how much of the loss volume was shut in versus inventory build?

About half of each, Gil.

Okay, and in the rate going to 45 to 46, how much of it is depletion of that inventory?

I'd say 1,200 barrels a day. So we still are in the process of finalizing, getting these trucks in to finish the job.

Okay. So you've been able to take the inventory sitting in tanks down, but you still haven't brought the trucks online?

We are in the process of -- during this month, we will have enough truck fleet to clear all that inventory and get all wells on production.

So the inventory is still there because the trucks aren't available?

Well, they are just coming in, Gil. This is a process, and so therefore, we'd probably have about 700 barrels a day that we will increase from where we are today, just by virtue of completing the truck fleet.

Okay, got you. Can you talk about, since Rich is there, was there any effect -- you raised the cash flow guidance for 2012 -- 2013. Was there any effect from different price decks used between the 2 different periods? I think the last one I saw was June, end of June pricing?

Yes, is based on that. I can't remember what the June strip price deck was, but this one reflects an early August strip price deck. And so I'm sure there's an impact from that, and then plus the Spraberry production growth that is highlighted in the slides.

Okay, but do you know -- you don't know what it is broken out between the price deck change and the Spraberry volume change?

No. We can get it for you, Gil. I just don't have the data here in front of me.

Because when I look at the strips at the end of -- not knowing the exact timing, they don't look that different. Or do you think they are different?

I don't think they are materially different. I think most of it is going to be coming from the production, but I am sure there is a contribution from both. I just don't know the exact mix.

Okay. And then, last question. With the waterflood project, could you just review for us, based on what you're seeing, what the lifting cost of those barrels are, given the water injection incorporating both maybe higher cost water because of the water issues in the area combined with the fact that you are actually disposing of produced water, which saves you water hauling?

Yes, I think the costs on this are extremely low, and you hit the nail on the head there. What happens is we are taking produced water, cleaning it up, and re-injecting it. So we don't have to go dispose of it. So actually, in a waterflood project of the type we are talking about, it's a very significant cost savings and very low capital, just for those 2 reasons.

So the LOE is lower than your average Spraberry LOE?

Far lower.

Okay. Great. Thanks.

Let's go to John Nelson with Macquarie.

Thanks for taking my call. I guess just to come at the same question Brian asked, maybe in a different way. You're out your Spraberry production guidance. Still looked a bit conservative to me on a 45 rig program. I'm not sure if that has to do with longer drill times from deepening the wells, so I was just wondering if you can give an update on what the right blended average spud to spud we should be using going forward?

Right now we are averaging about 1.7 wells per month per rig. So that's kind of a good rule of thumb for you.

Great, thanks. And then, the Mississippian well test, you said it was in the north, but what county was that in?

Martin County.

I'm sorry what was that?

Martin County.

Midland and Martin are the 2 counties that are the most important for all 3 of those zones that we are doing deeper in.

Okay, and just last 1. I know you talked about the land lease sale coming up in September. Do you guys think you will be participating in that? Or are you just saying you will watch it for a potentially high rate?

Yes, more of the interest level. The last lease sale, all of the acreage was going for about $3,000 per acre. So it will be interesting to see what happens in this. But it's all been nominated. And we pretty much have 15% to 20% of our acreage down in this area already. So, we are just -- it allows it to watch, and most of it's held by production, so it allows us to watch the performance from the horizontal efforts by the other companies.

Great, thanks.

John Freeman, Raymond James has our next question.

Hi, guys. On the discussion on the white sand versus ceramic, obviously sounds like, so far, it has been pretty clear, the savings with not really giving up much on the performance. How much more would you need to see before you'd think about changing the well mix next year from 30% sand versus ceramic?

Well, John, as you know, a lot of the deeper areas, as we move south and east in that trend, are going to require ceramics. And what we are going to be doing is pushing the envelope as hard as we can. The number anticipated for next year is about 30%, but I think, probably, we could do a little bit more than that as we edge out and continue the process of learning the impacts of using white sand. So I would say we would probably be over 30%, but it's clear, there is a substantial amount of the acreage we need ceramics.

Right, that's helpful. And then, 1 point of clarification in the release. When you all said that you forecast what your fracs and requirements are through 2015, does that mean you all have -- are working to secure that? You already have secured it?

All of those are under contract, John. All of our sand needs for Permian are under contract.

Through 2015. Okay. And then just last question, is there any gap at all that you all see in your current vertical integration model, like some business that you are not in right now that you think you may want to add if you look out several years?

I tell you what, at this point time with our VI, we're pretty much -- got everything. We're close to having everything. There are certain things we don't want to get too much of because it is not something where we're worried about cost creep, but if you take a look at the bottom of slide 19 you will see that our VI stuff has got us pulling units. It's 23 pulling units, it's hundreds of frac tanks, several hot oilers, water trucks, BOPs. We just acquired a bunch of construction equipment to basically do a bunch of our own dirt work, and we have a substantial number of fishing tools.

That pretty much covers the gamut. We're not going to be 100% self-sufficient on vertical integration, but in all of these areas, we realize there's substantial savings. We probably save $30 million a year just from those areas themselves, not counting the frac fleets and so on. So there's a substantial savings by doing a lot of this work ourselves. But from here, I think we will look at just piece meal, picking up additional equipment where it makes sense.

Great, thanks, guys.

Also, John, we are budging less than $50 million for VI next year. So you'll see it come down from $300 million to less than $50 million going into 2012.

You know it's gotten pretty big when you all can just refer to it as VI, right?

I just coined a new acronym. I expect to see that in your report, John.

All right.

At Global Hunter, let's go to Dan Morrison.

Actually, think all of my questions have been answered. Thank you.

Okay, Dan.

Thank you very much. Let's go on to Sven Del Pozzo with IHS Herold.

Yes, good morning.

Good morning.

Would you care to comment on the Eagle Ford Shale production currently?

No. Obviously we have a range of 14 to 17. We feel confident we will have that range, but, it is increasing daily. So the only reason we gave out the Spraberry number is just to show -- a couple of people have focused on the fact that we have not been executing on the Spraberry and also talk about the fact that we had the truck issue, and the truck issue has been solved. So we are not going to be in the habit of giving out on-the-time production all of our assets.

I see.

But it's executing. And our guidance is 14 to 17, so it will be up substantially. So the number of wells, you can sort of take -- at our average production, look at the number of wells that are coming on, and then that's pretty much -- gives you the information.

Okay, thank you, Scott. And, are your wells confidential? Like the most recent wells? Can we get well data for them on the Eagle Ford still?

Yes, you can go to the Texas Railroad Commission. We have to file with them, and it's always a couple of months behind, but you can always go to the Texas Railroad Commission and get public data. Some of the other services pick it up later than that, but obviously, the best way is go to the Texas Railroad Commission.

Okay. Now, after you make your midstream investment in the Eagle Ford, can we associate a number of wells that, in the Eagle Ford, that the midstream investment could support?

It is built to support every single well.

And the timing of that would be -- you are always going to be ahead on your midstream capacity versus your production?

Well, the CGPs, as you know we have 2 more coming on this year, but those are always built in a throughput capacity sense, much higher than the production so as to make sure we have adequate room for wells. And also, they are modularly designed so they can be easily expanded or contracted in an area where you have done doing to drilling. So the fact is, we will be done with the buildout of all those facilities in 2013 or so. And then we can expand past that point.

Okay. Could you give me an idea of your water sourcing for the Eagle Ford frac jobs?

Yes, water down there comes from several different sources. We get water from some shallow aquifers, and in addition to which, we are also buying water from surface owners and, in fact, from various surface owners in the area where mineral rights allow the owner to be able to sell the water. And so it comes from a wide variety of different suppliers including some river water as well. So it's really, in this case, it's a lot of different ways that we are sourcing water.

Okay. Spraberry trend, just from your press release, when you're talking about the Strawn and Atoka both being present in certain areas, it sounds like the incremental 110,000 per BOE, if you compare that to your old Spraberry type curves, say prior to 12-31-10, it would basically double that, I'm thinking. Correct me if I'm wrong. And what's the -- from a top-down basis, what's the completed well cost for -- in total -- for a while like that?

Well, go ahead, Scott.

You are right on -- we could have a 220,000 barrel well, but if you remember, the 110 is up to 140 now.

Yes.

Based on the fact that we're opening up shale zones in the Wolfcamp. So you could get a 140 and up to a successful Strawn Atoka well, so you could get up to 250,000 potential on a lot of our acreage. So that is the plus side.

And from a -- what should I be thinking for a completed well cost for a well at that?

You could get as high -- I am more confident that the team will not spend $750,000 on an Atoka well. So I think the water frac will work. Then also, they are going to experiment with running no intermediate casing. But our initial wells, we did spend $750,000 with the Atoka. So the Strawn is very little. So it could be a range of up to $2 million is where I think the ballpark is going to be after drilling several wells.

That would be the average well cost, and that does not consider VI. To the extent we are using our own facilities, the number is substantially lower than that. I think we've already publicized that that VI can produce the well cost in Permian something like $500,000 per well.

Okay.

Do you mind calling us back? We have some more -- if you don't mind calling us back, will be happy to --

No problem.

A question now from Joseph Allman, JPMorgan.

Morning, this is [Jessica Li] for Joe Allman. I have a really quick question on your Eagle Ford wet gas takeaway capacity. What is it currently? And, do you project that -- do you project growing going forward?

I will have to get back to you on that, Jessica. We have substantial capacity to take gas out of the area, and we are actually tied up at 3 different contracted parties of that Scott had mentioned. I just don't have the number off the top of my head. We can get that for you, and so, please call back, and we can get you that detail.

Okay, great. Thank you.

And our final question at this time is Richard Tullis, Capital One Southcoast.

Thank you. Good morning. Just a couple of quick 1. I apologize if you went over this already, busy morning. I saw you added a small amount of acreage in the Barnett Combo play. What's the ability there too materially add to that? Is that all pretty much leased up around you at this point?

We're hoping to get up to about 100,000 acres over the next 18 months. So we are also -- we have a program, some of our acreage, we only own maybe 75% of a drilling location, so we are picking up the other 25%, too. So we see hopefully getting up to about 100,000 acres.

Okay, and Scott --

1,000 locations.

All right. And just the last 1. I know you plan on doing a couple more of the horizontals in the Permian. When do you think you would have another well results update on that?

Tim mentioned that we are drilling our first Tippett Shale well. It's in the lateral now. We are going to drill 4 of those over the next several months. So it won't be fracked probably for another 4 to 6 weeks. So we will give updates over time in our horizontal program.

So you won't wait until you have all the wells down?

We could. But I just don't know at this point in time.

Okay, that's all for me. Thanks a bunch.

With no further questions, I will turn the conference back over to the Company for any additional or closing remarks.

Again, thanks. We appreciate everybody taking the time. We know it's a busy day for everyone. And we look forward to seeing everybody in the next quarter. So, thank you.

And at this time, we conclude our conference call. Thank you very much for your participation. Have a great day.