先鋒自然資源 (PXD) 2011 Q3 法說會逐字稿

Welcome to the Pioneer Natural Resources third quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer, Tim Dove, President and Chief Operating Officer, Rich Dealy, Executive Vice President and Chief Financial Officer, and Frank Hopkins, Senior Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the Web site, select investors, then select investor presentations. A replay of the Webcast will be archived on the Internet site through November 23. Today's conference will be recorded.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page 2 of the slide presentation, and in Pioneer's public filings made with the Securities and Exchange Commission.

At this time, for opening remarks and introductions, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Good day, everyone. Thank you for joining us.

Let me briefly review the agenda for today's call. Scott will be the first speaker. He will provide the financial and operating highlights for the third quarter of 2011, another strong quarter for Pioneer. He will then update you on the Company's production outlook for 2014 and our recent drilling success in the horizontal Wolfcamp Shale play.

After Scott concludes his remarks, Tim will discuss our drilling results and plans for the Spraberry, the Eagle Ford Shale and the Barnett Shale combo play. Rich will then cover the third quarter financials in more detail and provide earnings guidance for the fourth quarter. After that we'll open up the call for your questions.

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

Thanks, Frank and good morning or I guess we're moving into the afternoon now with earnings calls in some places. I'll start on highlights. Slide number 3.

Again, we had a tremendous quarter of adjusted income, $160 million, or $1.35 per share. It does exclude our mark-to-market of $191 million, or $1.60 per share. What's more important is that production of above mid point on our guidance of 128,000-barrels of oil equivalent per day, above 9,000 barrels a day, that is an 8% increase versus second quarter. Oil is also up 17% on the oil side, obviously, as coming from Spraberry, the Eagle Ford and the Barnett Shale combo play are three big growth plays.

This follows the production increase of 7,000 barrels a day from first quarter to second quarter. And also with our guidance going into fourth quarter, we expect the production growth of 10,000-barrels a day equivalent over the next -- and I think we're already up as Tim goes over each of our three key growth areas, based on current rates we're already up 11,000-barrels a day going in those three areas going into late October, early November.

We had 19% US production growth from third quarter 2010 to third quarter in 2011. We expect US production growth at 22% from 2011 to 2012. We're going to continue going into next year focused on US production growth as our last international asset, South Africa. Next year we'll be down below 2% of our production and 2013 down below 1% of our production.

Going into each of our key assets, just summarizing quickly before Tim goes into more detail, all of our liquids rich plays are exhibiting strong very, very strong well performance. We averaged 38 rigs in the Spraberry during the third quarter, continue to see tremendous success in the deepening intervals including the Strawn, Atoka, and the Mississippian.

Tim will go into more great detail, but its got the potential to add up to 110,000-barrels of oil equivalent in each of those key areas. And that's pretty much most of our deeper vertical drilling is in the top 80% of our acreage of 900,000 acres, and that's where we're getting the best returns. We did deeper drilling and that's where most of our rigs are running in that area. Also, we had a strong well performance in the Eagle Ford and the Barnett Shale combo, which Tim will focus more on in some more detail.

I think, I read several analyst reports today and most of you all got it. In fact, the most important point on the highlight page is the fact that we had a significant discovery 60 miles away from EOG in El Paso's main drilling area with our -- really our first Wolfcamp Shale into what we call the upper and middle Wolfcamp section. We had a peak seven day average flow rate of over 700-barrels a day equivalent, a 24 hour rate of over 800 over 850-barrels of oil equivalent per day, both rates are flow line restricted. We calculated there will be somewhere over 1,200-barrels of oil equivalent per day in regard to the flow line restriction.

What's most important is that we have well over 200,000 PXD acres for this play. This play is going to end up being one of the major all focus plays over the next several years. It will allow us to grow significant double digit rates for several years to come.

We're only focused on the Southern 200,000-acres, primarily you'll see later is the fact that we have not been drilling vertical. The returns vertical are margin. You don't have the deeper horizons and the Spraberry gets thinner and thinner in this section. So, we're really focused on about 200,000-acres to the South over the next several quarters.

Vertical integration is still enhancing our execution. It's saving us over $450 million per year, essentially our investment's already paid out. We'll talk more about it later.

Slide number 4, in regard to our growth rates. We're targeting still 18% compounded growth rate for 2011 to 2014. Again as a reminder, this excludes anything from the deeper horizons in the Spraberry trend area from the Strawn to the Atoka, and also excludes the horizontal Wolfcamp play.

We expect full year production of about 125,000-barrels a day equivalent. As we mentioned last quarter, it's toward the lower end of our guidance of 125 to 130 for the reasons foot noted below that happened to us primarily in first quarter. In addition, we have again unplanned down time during the third quarter in South Africa.

In the asset, we lost about a thousand barrels a day and for different reasons, we are going to lose about 1,500-barrels a day in the fourth quarter. This South Africa, as I mentioned, is going to end up being less than 2% of our production next year and less than 1% in 2013. What's happening is that the plant is reaching the minimum volumes of intake going to the GTO plant. We expect to have continued down time over the next 18 months.

Also, we have not mentioned this, but we collected $36 million for the third quarter in a take or pay from Petro SA. It covers production in 2009, 2010, it covered three periods of down time during that period. As we continue, that was about 1 million BOEs.

Because, on the take or pay, from an accounting convention, we have to put it in deferred revenue. We cannot count as production as we get paid for that down time. Over the next 18 months, including the fourth quarter, we will continue to have probably down periods and we expect to continue to have take or pay claims and collect that over the next several quarters.

Our production, obviously, up from 111 to 119, up to 128 and at mid point up another 10,000 to 138. If you look at the mid point, it puts US production up 22% and then company-wide over the next three years 18% CAGR. What's also noted and we're starting to calculate it, our liquids percent increase. You'll notice on 2010 we were 44% liquids. We're already up to 52% liquids for third quarter, so our acceleration of our three key liquids play and then 60% liquids in 2014.

Going into a little bit more detail on the horizontal Wolfcamp discovery in our Giddings Estate well 60 miles away, it's really the first well in Upton County in the horizontal Wolfcamp Shale play. You can see we put our horizontal primarily in the middle between the upper Wolfcamp Shale and middle Wolfcamp Shale. Petro fiscal and coordinate announces shows we have substantial oil in place in both of those areas. Again, I won't go over the rates again, but unrestricted we could have taken the well on up to about 1,200-barrels a day equivalent. Micro seismic shows that we successfully stimulated both intervals, so obviously, we're very excited about this discovery and this play moving forward.

Going into slide number 6, in regard to the map of where this is located. You can see the EOG in El Paso continued to have with their announcements over the last 24 hours, continue to have very successful wells in both areas. The furthest area's about 60 miles away and then they are also El Paso and EOG have had success about 30 miles away, that is the mid point in Reagan County. We're in the process of drilling one more well in Upton County and we're going to put two wells in Rains County.

As I mentioned, we're going to focus on 200,000-acres that we think will be well above that over the next several years. As I said, this is a tremendous potential for us and a part of the area that we have not been focused vertically because the returns are more marginal. As I said, we expect to drill three more wells. One is drilling now, two more after that and, obviously, we expect to expand our horizontal drilling program in 2012, 2013, and 2014 over the next several years.

We started off with about a 5,800-foot lateral. The second well will be closer to 6,000 feet. And then the third and forth well will be drilling out 7,000 foot plus. And we think the optimum length will probably be in that 7,000 foot plus going forward.

Last slide on number 7, investment highlights. Again, we got three tremendous growth areas. Over 20,000 drilling locations with over 200,000-acres minimum and growing in the horizontal Wolfcamp play, we'll have well over a thousand locations there. That's not in the 20,000 at this point in time. That play will allow us to continue to grow significantly over the next several years, we're forecasting 18% plus through 2014. And also, production growth, operating cash flow of 30% and that's foot noted at $90 WTI and $5 gas.

Again, we're saving over $450 million a year with our vertical integration strategy. There's tremendous hedges in place, both in 2012 and it's not mentioned there, but you could look at it in back, we have 50% plus of the same commodities, both oil and gas, hedge in 2013. And then, obviously, we have a great balance sheet with debt to book of about 31%.

Let me turn it over to Tim to go in more detail of our assets.

Thanks, Scott.

Turning to slide 8, our third quarter operational results clearly show that the Spraberry trend is a very large field that keeps on growing and keeps on giving, and will do so for many more years to come, as Scott has alluded to. As a side note, it's the play also that has the largest number of rigs running in the US. It has about 11% of the total US rig count. And as the largest acreage holder, driller and producer in this area, we'll continue to play a dominant role in the field.

We're seeing strong and very repeatable economics on our vertical program which, of course, has been the focus in the northern part of this play, the top 80% of the play, as Scott has alluded to. Returns look very good and most of the returns we're calculating still are based on the 140,000-barrel BOE type curve that goes when wells that are deepened only to the lower Wolfcamp. We believe, as I'll show in the subsequent slide, that as we deepen the wells to the Strawn, the Atokan, and the Mississippian that our returns will be enhanced.

So turning to slide 9 and with the topic in mind, that is deeper drilling, this is an update of our activities and a review of the results of our vertical deepening program. As you can see in the top part of this slide in the third quarter, we have some very substantially positive results. And we're getting more data day-to-day in terms of giving us the confidence that the empirical data supports that deepening is really adding a lot of value. For instance in the Strawn, we've now drilled 113 wells into the Strawn, and for those wells for which we have 10 months of production, we believe we have about a 25% increase in cumulative production which is, obviously, a substantial contributor in terms of economics. Looking forward, we'll be completing about 25% of the wells that are in next years program in the Strawn.

In the Atoka, the Mississippian and the Atoka, of course, we've now done three well program, one of which was a zonal test which is completing the well only in the Atoka in the third quarter and it tested 127 BOEs per day on a 24 hour test. So, the objective there is to complete two or three wells more in this quarter and then we have enough confidence now to say our Atoka completions will occur in about 15% to 20% of next years program. Similarly, in the Mississippian, we're seeing very good results in the second well. It was a zonal test again, about 92 BOEs per day, and we have a couple more wells to drill this year and have about 10% of next years programs slated to complete in the Mississippian.

As you look down to the bottom end of the table, it has to do really more with the economics and the EURs expected from each of these zones. Suffice it to say, we think there's substantial resource potential that can be added, especially in combination. For instance, if we are in a situation where we have both Strawn and Atoka, we could increase EURs in the wells by some 110,000 BOE, so taking the well from 140,000 BOE to somewhere in the neighborhood of 250,000 BOE.

We've done a little bit more work in terms of the cost assessments for the Atoka. What you see here is a tightened range of the costs and that's because of the more work we're doing, we believe we can go to water-based fracs. We are going to need 5.5-inch pipe on bottom, but that will also, we believe, allow us not to have to use a separate casing string and an additional casing string, and that's why we've tightened the ranges there.

In the Mississippian, we've actually increased this cost mostly, again, related to the need for 5.5-inch casing and we are now increasing the number of stages pumped in terms of the completion in the Mississippian to two to three stages, each of which is adding cost. But nonetheless, each of these were very strong economics. In the case of the Mississippian, probably in the neighborhood of $10 per BOE, and very substantially lower even in the Strawn, about $3 to $5 per BOE. So, essentially what I'm saying is the deeper drilling is proving up and I think we're at a point where we can say it's going to become a big part of our vertical program going forward.

On slide 10 is a recap of what's happening on our Spraberry water flood. Of course, we have a flooded place since August of last year. So after these 15 months or so, we now have pretty good confidence that the production wedge is building as shown on the graph. This water flood is occurring only in one zone called the Upper Spraberry, that's 110 wells that we're talking about. So, we can pretty much define now that we have a significant impact on production and the key to this is that as we go forward I think that wedge will continue to build. And the result of that, at least in this one area, is we think we'll actually be adding reserves.

We've already added reserves in the third quarter for this water flood and we'll also be adding more reserves by year-end. The amount of reserves on this particular project being only 7,000 acres is not terribly meaningful just because of the limited number of wells, but the key is that the process is working. We're seeing the effect and the next step, of course, is to scale up this activity into other areas. We do have a larger 25,000-acre project that's been identified for 2012 and its being looked at and evaluated as a part of the 2010 capital allocation process.

Turning to slide 11, the proof is in the pudding in terms of reserves I guess. You see that we have substantial growth in production up to 47,000 BOE, outstanding quarter and we expect the fourth quarter to be outstanding as well. We have eliminated essentially all of our oil trucking issues that we were dealing with in the second quarter and part of the third quarter. In fact, we added 11 trucks in the third quarter. We now have 26 crude oil trucks operating in the field and we believe that's ample for our near term needs.

In addition to which, one of our further objectives is to make sure we can get more oil on pipe. We have 5,700-barrels a day of new pipeline take away capacity that's coming in the first quarter of 2012. As a result of all of this, we expect to be towards the high end of guidance for the year in this field.

Looking forward, we're still showing a very substantial growth rate. The production forecasts that you see here have been in place for some time, but it's important to note, and Scott alluded this, but these forecasts do not include deepening below the lower Wolfcamp. So, they don't include any impact from Atoka, from Strawn, and from Mississippian. And as mentioned earlier as well, it does not include what will be, we think, substantial impact from the horizontal Wolfcamp Shale drilling campaign as it has expanded.

Turning to Eagle Ford, that's slide 12. This is now, it turns out also, that a very important area from the standpoint of rigs operating. It's the second highest rig count area in the United States with about 200 rigs running and several operators in the play actually, we think, have been discussing infrastructure limitations that have affected their operations. We actually have a first mover advantage, we feel like having been in the play so long and having our CGPs in place to a great extent. And with our trucking and pipeline contracts in place, we've had essentially no infrastructure related issues during the quarter.

We are running 12 rigs and some of the data on those wells and rigs are shown in the box. Importantly, we are making strides in understanding the use of white sand as a profit. About 30% of the program going forward when will use white stand and we are seeing very good results and we compare white sand profit wells to offset ceramic prop wells and that gives us confidence that this is the right thing to do going forward, where it applies.

One very important component of the results in Eagle Ford is the fact that oil prices for Eagle Ford condensate and crude oil have been improving. In fact, in certain of our areas, we're now getting a premium over WTI of about $5 before gravity deductions. So, in general in our area, it nets to about a $2 premium to WTI after gravity. And that compares to numbers earlier in this year that were somewhere in the neighborhood of $7 to $8 below WTI. So, we've had a substantial improvement and it has to do with increasing refinery demand or the lighter Eagle Ford production as it's attractive today in consideration of the fact WTI is still $18 below Brent.

Turning to Slide 13, we've gotten a lot of requests over several quarters for well performance data on the Eagle Ford Shale and so we thought we would share some of the third quarter results. These are third quarter wells, 24 hour flow tests. As you can see, we're exhibiting very strong rates of production for condensate, crude oil, NGLs as well as natural gas. I'm not going to go through each one of these wells other than to say the average well in this table -- on these tables is 2,269 BOE per day. And what you're seeing is production has become more repeatable and predictable as we drill more wells up and down the trend.

Slide 14 then, again, shows what the effect is of getting these wells drilled and put them on production. We had a substantial ramp up in the third quarter. We came in near the lower end of the range simply because, as is the case is always, the number of wells you put on production is with the determinant of the amount of production you can announce.

We had some wells in terms of their pop dates slip until later in the quarter than we had planned and those wells were put on production, but didn't have as much of an effect on the quarter but they have a substantial effect going into this quarter. And in fact, we're currently at about 20,000 BOE per day, up from the 14,000 average, and essentially what that reflects is we're catching up on the pop schedule. And you see a substantial ramp up still in this field as we begin the process of acceleration, so you see this is going to be a substantial contributor to our growth going forward.

On slide 15, this is similar well data for the Barnett Shale combo play. We have shown very strong rates. In fact, a lot of these wells are exceeding their type curve when it comes to their early production.

We have substantial acreage position in this play that's growing slowly. We're trying to add more acreage, of course. We have been increasing our lateral length to 6,500 feet or so. But the important point is the average well here that's shown on the table is about 427 BOE per day. In general like I said, there are many cases exceeding early production type curve.

The effect of that is shown on 16 then. We're showing increases in the Barnett Shale combo play production to about 4,000-barrels a day. Third quarter up one, again, currently to about 5,000. And so what you're really seeing is you look across these key areas in Texas. So, all of the areas, Spraberry, Eagle Ford Shale, Barnett Shale, they're all showing continuing strong production growth which gives us a lot of confidence going forward.

And slide 17 recaps what I was mentioning earlier regarding the activity. We just happened to be in a position where we're in the two most active United States plays in both the Spraberry trend area and the Eagle Ford. Plus a significant position in the Barnett Shale play, the number eight rig count play. I think the rigs here represent about 70% of the total rig count. You can see as a result because of our position in these areas, we're very well poised to continue to execute and deliver strong operating results.

And with that I'm going to pass it over to Rich to discuss the third quarter financials and his outlook for the fourth quarter.

Thanks, Tim. I'm going to start on slide 18.

Net income attributable to common stock holders for the quarter was $351 million, or $2.95 per diluted share. As Scott talked about, it did include $191 million after-tax, or $1.60 of unrealized mark-to-market derivative gains as a result of lower commodity prices at quarter end. Also, so as adjusted about $160 million, or $1.35 per diluted share of adjusted earnings. That did include $26 million after-tax, or $0.21 of derivative unwinds that we did during the quarter, so that -- wanted to note that for you.

At the table below it shows third quarter guidance and our results how we performed against those, that guidance. You'll see that we were within guidance on all of the items or on the positive side, except for current income taxes which is were slightly higher due to the incremental taxes that we recorded associated with the take or pay in South Africa that Scott discussed.

Turning to slide 19, price realizations, you'll see that oil prices at the top they were down 11% during the quarter to $87.25. If you look at NGL and gas prices, they're relatively flat quarter-on-quarter. Just a couple notes on NGL prices, most of our NGLs all end up in Mont Belvieu. We had solid, strong demand in Mont Belvieu for NGLs, particularly given that the heavier part of the stream is more closely tied to LLS or Brent prices and we didn't see a drop in those prices like we saw in WTI prices. The bottom of the slide shows the impacts of our derivatives and BPPs on our reported prices as well for your information.

Turning to slide 20. Talk about production costs. Production costs for the quarter were up 5% to $13.47. Two main reasons for the increase. One in base LOE, we had saw increased labor rates during the quarter and some higher maintenance costs that we experienced during the quarter just on our routine basis.

The second piece is are natural gas processing costs, we're up about $0.39 due to unplanned down time at the Midkiff-Benedum plant in the Spraberry field, as well as we had take away limitations on NGLs there. So, we're rejecting ethane, so the impact was the down time we had higher expenses and two, with the take away limitations, we had less third party revenue as a result of rejecting ethane, the plant gets from a percentage of proceeds type contracts they have for products running through the plant.

Looking at slide 21, fourth quarter guidance. Scott talked about 136,000 to 141,000 BOEs a day of forecasted production for the fourth quarter. That does reflect the 1,500 BOEs of down time for October out of South Africa that's been already taken out of the guidance range. The rest of the items here in terms of guidance are consistent and very similar to what we've had in past quarters, so I won't go through each one individually, but they are there for your review and modeling.

So, with that why don't I stop there and open up the call for questions.

(Operator Instructions) We'll take our first question from Dave Kistler with Simmons and Company.

Real quickly, with your commentary that the production growth doesn't have upside potential from Strawn, Atoka and Mississippian zones, as well as horizontal Wolfcamp, if I just look at the numbers you're throwing out for tying in percentages of each of those areas into wells in 2012, is it fair for me to come to a conclusion that your production guidance could be muted by as much as 5%?

Dave, this is Scott. Yes, I think the big swing factor we've seen WTI in 2012 move from $78 to $92 or $93 over the last 60 days, and I think a big swing factor, even though we have some great hedges that protects it down that locks in $80 and 550 gas. We have a slide back on slide 24, we have a lot of levers depending on what the price is, but the price is strong, we have, obviously, huge upside potential with all the things that you mentioned. The price is weaker, WTI we have huge flexibility to keep our numbers similar to what we've been showing in the last 12 months, as listed on slide 24 in the appendix.

Okay, I appreciate that and then thinking about slide 24 for a second, one of the things that isn't mentioned in there is dropping down assets into the MLP and maybe a consideration of spending any of the service assets. Can you maybe comment on those sources of capital for '12 to fund any kind of CapEx above discretionary cash flow?

Yes, in '12 & '13, we do have the -- I'm going to put them all into one category because we've talked about non-core assets also. I'm going to put non-core assets, including PSE units or drop downs all in the same category, so we always had that option in addition to '12 or '13 or '14.

I'd just comment, Dave, on the question of spinning out our services business, that's way premature. We're building fleets as we speak. We have more coming in next year in terms of pumping services, so any consideration of that is some time off.

Can you give us just a little bit of clarity on how much pressure pumping capacity from a horsepower perspective you have coming in, in maybe even just this quarter and then through 2012?

I think by the time we get done at the end of this year, we'll be about 225,000-horsepower. We've got about 50 coming in next year. That 275 will make us the thirteenth largest pumping services company in North America.

Great. One last one, I apologize. Looking at your rig mix when you talk about 45 rigs potentially or have in the past in the Spraberry, can you just talk a little bit about how that might change given that the mix could move to some horizontal Wolfcamp wells? Should we continue to target 45 or is that going to be very flexible?

Yes, I think a combination on future results on the Wolfcamp Shale play, adding most likely adding rigs there during periods of in 2012. A big factor is what's going to happen to WTI. So, at this point in time, we still don't plan ongoing to 45. We plan on adding rigs, but a big factor is what WTI. WTI, if you notice my last point on slide 24, it's slowing down the rig count acceleration, so we have that opportunity also in a couple of our key areas, but the bigger this Wolfcamp Shale play gets, we anticipate adding rigs there. There is a possibility we may slow down some of the vertical at some point in time.

That's helpful. I appreciate the clarifications guys.

Thank you, sir. And next we'll hear from Will Green with Stephens.

You mentioned that the horizontal Wolfcamp would be focused in kind of the Southern most 200,000-acres. I know it's early. You've only drilled two wells there. Do you have a good sense for how wide laterally those two wells are draining and enough to give us a sense for potential spacing there or is it just way too early to even get into that?

Yes, first of all we've only drilled one well. The other well, if you remember, we drilled one in the carbonate very far Northwest and we had a very poor frac job. The second well was in the lower shale and I think people like Laredo and Apache are calling it the Pin Shale. It's the shale zone at the bottom of the Wolfcamp on top of the Strawn. That was our second well. This is our third. It's our first well into the upper middle Wolfcamp, but we're expecting with over 200,000-acres, 140-acre spacing right now drilling 7,000 foot laterals that we could have over a thousand locations, so 140-acres is the answer, right now.

Great. I appreciate the clarification there. And then I wonder if we could jump over to the Eagle Ford. It seems like that versus a lot of the peers that are in the play, your wells are really performing outstanding and I guess just jumping to my question, what kind of type curve are these wells following at this point, if you had to look at it on an average basis and do you guys anticipate putting out a type curve on that at some stage?

Yes, I think the fact is the areas we're doing the drilling in are exhibited here as really some of the best areas in the overall complex of the Eagle Ford Shale and a lot of people believe that the liquids rich condensate area, because of the energy in the system was a significant amount of gas in the system, will lead to higher EURs in this area and higher productivity, importantly. We're still using roughly a 6 BCFE type curve. The type curve is different in the various areas though. That's one of our complexities is you go from the dry gas window in the South and East to the North and West where you get all the way into the oil window. We have various different type curves.

So, there's no such thing as one type curve, but the fact is these wells are performing very well, as you said, and a lot of it is due to the fact that we have an excellent team of people working on this. We've drilled enough wells right now where we have the technological advantage. We have the most technology in the play in terms of knowledge and all that's coming to bear. We're doing a good job in terms of drilling the wells and drilling them cheaply as well.

Great, and then just one more just to hit on the cheaply as you mentioned. You talked about you're seeing similar results going from ceramics to sand. Is that on a EUR expectation basis or is that an economics basis? In other words, could we see you guys maybe sacrifice a small amount of EUR for a significant amount of cost?

Yes, I don't think we're trying to sacrifice anything. What we're trying to do is get an understanding because the fact is we've just started this process of using white sand this Summer, so it would be way premature to determine the exact ultimate EUR effect on the ceramic well versus the white sand well. That said, early well performance is showing similar data for offset wells. In other words, ceramic versus white sand. And that's an indication, at least in the short-term, that well results will be very good and on that basis, very economic similar to the ceramic pumped wells. But to answer your question, it's going to be hard to know for some time until we really know the exact EUR deltas between offset wells.

Great. I really appreciate all the color and congrats on the quarter guys.

Thank you.

Thank you, sir. Next up is Brian Singer with Goldman Sachs.

Going back to the slide 24, given the more one off items in this year's capital program, can you comment on how much spending you think you would need in 2012 to achieve just the 20% growth as opposed to the 20% plus?

Yes, I've looked at some numbers, even down to 80, 85 Brian in implementing some of these things that we can achieve 20% type growth rates.

I'm sorry, I guess the question is what level of CapEx budget would achieve that, would you be able to do that at --

Spending cash flow basically at an $80, $85 number, it's going to be around, cash flow is going to be around 1.7 in those numbers, 80, 85 we could spend 1.7, 1.8 and achieve the type of growth rates.

Got you, thanks. And then when you think about developing the horizontal Wolfcamp and I guess this also would depend on the commodity price environment, but do you see the incremental rig commitment and capital commitment as incremental to your program or would you think about backing off in other places?

I was asked already about the vertical Spraberry program and, obviously, that would be an area that we could slowdown the acceleration of 45 rigs. The returns it looks like are very, very similar. You get much higher production rates on the horizontal well per dollar invested versus a Spraberry deeper well. So, a Spraberry deeper well, as Tim mentioned I think, is running up to about 1.9 million all the way to the Atoka, and so those wells may come on 120-barrels a day and so these wells come on a 1,000 barrels a day for about $7 million. So, you can see you get much more production by dollar invested in the horizontal play. So, I see over the next two to five years it will be a mix of those areas and the big factor is the WTI comes back stronger as it has in the last few weeks and the $100 plus next year could do both.

Got it and then lastly, on the $7 million to $8 million well cost in the Eagle Ford, does that reflect the benefits of vertical integration or are there kind of downside or I guess the potential for inflation there next year?

Brian, that's essentially a blended well cost. So, today, remember we've got one of our own frac fleets out there as well as a third party and by the end of this year, we'll have two out of the three that will be Pioneer operated. So, what you see in those numbers is a blended number of the two.

Great, thanks.

Thank you. Moving forward, we will hear from Leo Mariani with RBC.

Yes, hi, guys. Just in terms of the Wolfcamp, I think you mentioned that you guys are still out there buying acreage, just wanted to get a sense of how much you think maybe you could kind of pick up in and around your existing position. And then maybe kind of comment on an infrastructure there in that 200,000-acres.

Yes, we are -- we have bought land in September, we're continuing to look at adding additional land over the next several weeks and months. I think the big infrastructure, we don't at this point in time with our recent agreements of expanding Midkiff-Benedum with Atlas and also NGL take away, probably the next big item that we have to look is the type of volumes we could be seeing from this play. Right now there's about 16 rigs running. Obviously, you could get a lot higher quickly over the next several months, so it's more about crude oil take away of adding more trucks, and so we're addressing that now as we speak. There's also the line to the South that potentially could come in with Magellan and Longhorn that will be taking crude down to the Gulf Coast instead of going to Cushing. So, those are some of the issues that we're looking and addressing and we'll have more answers over the next several quarters.

How about gas processing in that general area?

I didn't want to mention, our two of the largest plants in the area is Midkiff-Benedum and those plants are just Northeast of our discovery Giddings Estate and we are in the process of expanding those plants significantly also. It looks like the gas/oil ratio in most of this in our areas is about 1/1000 and it's basically the gas and oil ratio. So, we'll end up having 90% liquids plus in a typical well as you get more into further into Southeast, the gas/oil ratio does pick up more significantly, so we are expanding our plants. We were well down that road already and also NGL take away at our plants.

Okay, and could you guys kind of comment on any issues in terms of needing to drill the whole leases in this area?

Yes, we have -- on our map, we have 75% of production held by production of our 900,000 acres and that pretty much holds true in the entire area. We do have some leases that will expire over the next two to three year leases, and so we will have to protect those.

Okay, so just to clarify on the 200,000-acres to the South, you guys are roughly 75% [AGIP] there, is that right?

It's about the same ratio of the entire trend, 75/25.

Okay, I guess just looking at your production guidance, you guys had a range for the fourth quarter of 136 to 141. Kind of looks like in some of the numbers that you gave, when you kind of look at some of the individual areas, that you guys are trending closer to the 141 at this point. Is the range just a function of who knows what happens in the next two months and clearly there could be some down time, how should we kind of think about that?

Yes, the biggest item we mentioned. South Africa, again, it was off the entire month of October. It's back on now and I sort of alluded to, we don't know when it's going to go off and on so we've built in a loss of 1,500-barrels a day, so the entire month was off and so that was the biggest factor. So, with the rates that Tim gave on current rates, if you put South Africa back on at about 4,000-barrels a day, you can see the numbers that you get, so that was really the big adjustment.

Got you.

So, South Africa off the month of October, the range would have been much higher that we would have given you. But as you remember, we do have a history of take or pay and as things go down over the next several quarters, we expect to collect that but we can't come back and count that as production, deferred revenue.

Okay, and I guess with respect to your Spraberry water flood, obviously, you guys are experiencing pretty good early performance here. What do you guys think potentially could be your incremental oil recovery? I'm sure it guys have some models that have kind of looked at that, just trying to get a sense of what that could be in the play.

Some areas, Leo, if you look to the past history of these floods in the zones that are flooded, you could actually get a substantial increase in EUR. Sometimes you see as much as a 50% bump in production, ultimately, maybe a 25% to 30% increase in reserves.

All right, thanks, guys.

Thank you.

Next we'll hear from Brian Corales with Howard Weil.

Good morning, guys. It looks like the Eagle Ford, you all were restricting the wells. Is this just as a clean up or are you all restricting them kind of going forward?

They're restricted going forward. If you looked back to the history of what's happening in the Haynesville and other plays, I think the data suggests pretty clearly that restricting the wells probably is the right thing to do for the long term. So, we're bringing the wells on at lower choke settings, generally 12/64 or 14/64 to avoid damaging the reservoir and we think we're seeing lower decline rates as well, which is the empirical data that suggests this is probably the right thing to do.

Is that an EUR increase and if so, maybe is it too early to quantify?

I think it is ultimately a EUR increase. It is too early to quantify though with a lot of the wells having been on way less than a year, so you have to give us some time to quantify what the effect would be. In the early stages what you can say is, we see in a deduction in the decline rate which would tend to make you believe you have an EUR increase.

Okay, and you talked about the $7 million to $8 million blended cost. Is that using ceramic proppant?

Yes.

And what do you save by using white sand? Is that about $1.5 million?

$700,000.

Okay, and then finally could you maybe talk about cost? I know this is kind of the first Wolfcamp horizontal in the Southern area. Are you all targeting a certain cost there and is that going to vary within the 200,000-acres?

Yes, it will vary. We're targeting $6 million to $7 million, that's also net using non-PHD frac fleets, so -- and the reason the range is, it's much deeper, we're about 2,000 to 3,000 feet deeper on our Giddings area versus where 60 miles away where EOG is. So, we're going to see a range, as you move South and Southeast on our acreage in that map in Reagan County, our AFE should be about the same as EOG. So, that's a blended -- six to seven is a blended rate.

All right, guys, thank you.

Next we'll hear from Amir Arif with Stifel Nicolaus.

Thanks, good afternoon guys. A couple of quick questions. First, the production numbers that you provide for 2012 by region in Spraberry and Eagle Ford, can you tell us how many rigs you're assuming for the '12 programs like Spraberry 38 or assuming you do go to 45 to get that '12 number?

Yes, all of those are the same rig rates that we put in on the last several quarters, again it's 45 and 14 on Eagle Ford and 4 on Barnett.

Okay, and did you say that you'll be able to achieve those with a CapEx as low as 1.7, 1.8 or is that assuming the 2.1 current levels?

That's one of the items as 1.7, 1.8 with slow rig count acceleration, that's one of the four items that we list on slide 24 as an option.

Okay, but --

And so under much lower oil prices, we would probably take some of the rig count down.

But you'd still be able to --

But still achieve 20%.

Okay, and is that just by shifting to more of the horizontals where you get the higher IPs per dollars spent?

That's even before this recent discovery. That gives us another opportunity we could probably get higher rates without cutting some of the verticals in Spraberry. That's not even built in that. This well just came on in the last two weeks, so obviously, it's a significant plus to that, but all my comments are referenced before that well came on.

Okay, and then --

And had a very conservative number out there over the last several quarters.

And then I think I heard you mention that the 200,000-acres in the South, that you're doing the horizontal drilling on, I thought you didn't have much vertical drilling but you said three quarters of that is still held by production, so it will just be an economic decision? There's no need to drill that area a little more?

No, a bunch of that acreage, we actually bought in some acquisitions. We historically, at our companies over the last 20 years, have not drilled -- we drilled very few wells in the Southern and we have a combination of University land that has to be drilled on and a combination of acquisitions that we've made from two or three operators over the last seven to eight years, and that's how we got a good base in that area. So, it was drilled by other operators, but historically being there for 30 years plus, we have not drilled in those Southern areas because of the poor vertical returns.

Okay.

So, a lot of its held by production for that reason because we bought properties from people that have already drilled wells on it to hold it.

I see, okay. And then on the horizontals, on the additional horizontals you're going to be drilling later this year and next year, are you going to be targeting the same Wolfcamp zone or are you testing --

Exactly the same intervals.

Okay, and then just a final question on the white sands in the Eagle Ford. You're seeing similar initial productivity out of the wells. Is there any issues over time with does the sand hold up as good as ceramics, or does it level off at a lower rate, any issues that would make you decide which way to go?

What I would say is it's too early to answer that question. We need to see several years of data. The idea that you have a similar IP rate gives us some confidence that this could very well work. We're going to have to see how well the sand holds up versus ceramics in longer term situation when the pressures come down the well. We'll be able to let you know the answer to that when that occurs.

Sounds great, thank you.

Thank you, sir. Next we'll hear from Brian Lively with Tudor, Pickering.

Just on the Wolfcamp acreage itself, it seems like right now the popular buzzword is JVs. You guys are clearly ahead and set the pace with your Reliance JV, that allows you guys to basically grow that asset within cash flow. Would you consider doing a JV on the Wolfcamp acreage?

Not at this point in time. Our focus is, obviously, on proving up our acreage, understanding it more and seeing how big it could be. That's always an opportunity way down the road.

Okay, and is that just more of you need to delineate first or is it just you feel just more options around capitalization?

We're excited about the play, but drilling -- if you remember, we drilled five wells plus before we even thought about the JV. We do have a lot more acreage here that's held by production than we did at the Eagle Ford, so it's always an opportunity down the road as we did in the Eagle Ford. But right now, we're just trying to get our wells down and evaluate the potential. We'll probably add more acreage, so it's something down the road, but right now it's not the focus. There has been no, to my knowledge, no JV in the Permian Basin to date.

Just not yet, right?

Yes.

Tim, I think this is a follow-up question, I want to make sure I understood. I think you said that for 2012, you plan to drill something like 15% to 20% targeting the Atoka, 10% in the Mississippian, I assume 25% or so is still for the Strawn. If that's right, my question is more is that scalable up and down regardless of where you guys at are on total rig count? Meaning, if you took rigs out of the Spraberry and drilled more Wolfcamp, would you still hold those percentages for your vertical program?

I think what we're really saying is the Atoka and Strawn and Mississippian wells are going to have stronger economics and higher productivity than just drilling wells to the lower Wolfcamp. So, I think if we were to for instance, as you said, reduce the rig count, I think we could keep those wells in the program because they are going to be more prolific wells. So, what you would be doing in essence is reducing a number of wells that are only drilled to the lower Wolfcamp.

That's percentage actually goes up with a lower rig count?

Correct.

All right, thank you very much.

Thanks.

Next we'll hear from Gil Yang with Banc of America Merrill Lynch.

In the water flood area, Tim, you mentioned that you think that maybe the EURs go up by -- the recoverable volumes go up by 30%. Is that of the original EUR or is it just for what's left?

That's the original EUR.

Okay, and when would you typically put a well in water flood? Would you put it on immediately or would you have to wait to get to a certain point of depletion?

Well what we need to do in the case of this water flood and in future ones is to properly drill up the area where the water flood is in place, and what I mean by that in this case is we've drilled this to 40-acre spacing. And this is the first water flood that's ever been done by some 40-acre spacing, the 7,000 acre flood we have in place now. As we look forward, its plausible that a 20-acre space field might even do better in terms of recovery rates and that's something we may want to consider, but the key to this is getting the wells drilled, having densely spaced wells and then, in addition to that, add a handle -- a few injector wells and/or convert a few producers that are existing into injectors and that way all you've done is drill up the field and you start reintroducing produced water. So, it's an elegant way to increase production on the one hand, but also allows us to dispose of produced water on the other which is, generally speaking, costly. So, I think it has a lot of potential and we think it's in the neighborhood of 40% to 45% of our acreage where this could apply.

Okay, and can you -- what's sort of the rate of return on the incremental spending that you need to do to get that extra 30% out?

Well, let's see. It's the case that the costs of this are very small. If you look at the existing project, it's about a $6 million capital cost. As an example of that, I think we might be booking somewhere in the neighborhood of 200,000-barrels from this existing flood by the end of the year and that's just this years production bump. So, I think that's going to be increasing, so you can see the math on it is going to get exceedingly beneficial to us.

Okay, are the operating costs, are the incremental operating costs for the incremental barrels actually negative or still positive?

Well they are slightly positive because you have to process the produced water and you have some electrical needs. We do not pump under high pressure, but you have some positive costs but they almost are entirely netted out by the savings on the disposal of water.

Okay, great. And if you look at 20,000 locations you have in the broad Spraberry and you may have addressed this already, but if you drill a thousand horizontal wells in the 200,000-acres, would you write-off any of the -- not write-off in the accounting sense, but just sort of would you reduce that well count to 20,000 by any?

No. Gil, as I had mentioned, we have not drilled much in the South mostly due to the acquisition. So, we didn't have -- since the returns vertically are marginal, it was not in our 20,000. Our 20,000 is a high grade. We've probably got over 30,000 locations in the Company, so we high graded the 20s and the 40s to get to the 20,000.

So, the 200,000-acres doesn't really have much of that 20,000 inventory?

That's right.

Okay, and in terms of the Atoka costs range narrowed, I think Tim you mentioned why. Can you just sort of highlight exactly why that potential incremental cost range changed?

Sure. In the last call I think we had numbers that ranged from 250,000 to 750,000 and the reason for that is we're just addressing the question of do we have to use CO2 conveyed fracs or could we use cheaper water conveyed fracs. The next question was were we in need of an additional intermediate string of casing or not depending upon the depths of the wells, and after further and more analysis and having done the testing of three wells now, we've come to the conclusion that we can focus most of the program on water conveyed fracs. We can eliminate the additional string of casing by using 5.5-inch casing on bottom as opposed to 4.5-inch. That, of course, has a cost associated with it and that's why the costs are what they are. In addition, we believe in most cases we'll be pumping two stages instead of one in terms of the completions and when you put the numbers together in relation to all those that's how you get this range, 300,000 to 350,000, that's now essentially a tightened range with more data.

Okay, great. That's helpful, but do the two stages cost more than the one stage? Or is it --

Oh, yes, incremental some costs on your second stage, sure. If nothing else time and effort.

Right, right. Okay, thanks a lot.

Thank you, sir. Next we'll hear from John Freeman with Raymond James.

Hi, guys. Just following up on the deeper intervals, again, on the Spraberry, I'm just trying to make sure that I'm sort of thinking about this right. If you sort of add up all of the percentages for 2012 on the various zones you're going to deepen to it's like 50%, 55% of your wells, but in your 2012 guidance, are you all embedding in some of that assumptions that you're going to do the Strawn and Atoka or Strawn and Mississippian in the same wells?

Correct. Wherever we can do that we will. Now there's some cases where you'll be drilling Strawn only wells, but the fact is in a lot of cases what you'll be doing is seeking out the opportunities to drill the wells through the Strawn and Atoka, where that exists and typically in the other case, Strawn and Mississippian, where that exists and the Atoka and the Mississippian, generally speaking, do not overlap.

Right, so is it probably too early then, Tim, to sort of have some rough idea if you sort of just assume that in some cases you're doing Strawn and Atoka, or in some cases Strawn and Mississippian, what absolute percentage of wells are going to be deepened for the vertical program?

I could get that for you, John, because I know we already have the wells pinpointed, but I just don't have it off the top of my head. If you call back to Frank we can get you that information.

Okay, great. One other question. I know in Alaska you've got a couple pretty important wells that are coming up. One of them is a deep test I believe that was scheduled for this Winter. Is there any update on the specific timing on that well and potentially when we might have results?

Yes, John, in three months from January through March, is when we'll be drilling the two wells. One will be fracked similar to what we do in the Eagle Ford, the horizontal Wolfcamp play in the Spraberry and then the other one is the Ivishak well. The spud date well be in January. We have to be out of there probably by the end of March, so I'm guessing at the earliest it will be May earnings at that point in time.

Great. Thanks, guys, I appreciate it.

Thank you. Next we'll hear from Sven Del Pozzo with IHS Herold.

Yes, IHS Herold. Hi, guys. Just on slide 6 again, horizontal Wolfcamp, just wondering if you have vertical well data to support the risking process that you use to call these 200,000-acres perspective.

Yes. If you look at the bottom of slide 5, petro physical is log data and we have core analysis in the entire 200,000-acres in that area and so with the success of the wells by EOG, El Paso and approach raises our confidence level. So, it's a combination of logs, which is petro physical data, and core analysis.

And do they go deep enough to actually give you a look at this deeper Wolfcamp that you're targeting?

Yes, there's a lot of deep wells that have been drilled down into the Devonian, going deeper looking for exploration prospects in both of those counties.

Okay, and I'm looking at the vertical wells drilled and a lot of vertical wells drilled in '08 and '09, right where your acreage is just like on your map that you show, so are you guys saying that, that's the area that you think, also with that arrow that you've got on slide 6, where it says 60 miles there, is it that whole area that you're thinking between those two, the arrows, basically where it says 60 miles?

No, I would focus on Upton and Reagan Counties, that's 200,000-acres plus.

Okay.

Don't get focused on the 60 miles. Those two arrows.

Okay.

In other words, you don't have to be along those arrows to have good wells.

All right, and how much does the vertical well data help you? Do you use that data to map out these horizontal wells?

Exactly, yes.

Okay, and where are your 20-acre pilots that you mentioned in the release?

Our 20 acre pilot drilling is essentially up and down different areas of the field. But it's normally North of where you're talking about here, Sven. It's in the northern counties, Midland and Martin County and so on.

Okay, and lastly, when you say the Strawn, you feel it's about 40%, it's on about 40% of your acreage. I guess what causes you to exclude the other 60% and include the 40%?

Well, Strawn is not ubiquitous like the rest of the Spraberry pays, so it's not everywhere in the whole 900,000 acres. Secondly, where it exists, there's a porosity cutoff that needs to be met before we complete in the Strawn, so it's a combination of those thing that brings it down into the 40% range.

All right, thank you very much.

Thank you, sir. Next we'll hear from Dan Morrison with Global Hunter.

Good afternoon. I know its gone long, but a couple quick questions.

Yes, Dan?

You said your micro size indicated you'd stimulated the full 800-foot thickness. Two things. How much sand are you pumping per stage and then also, what's the micro size say about how far out you're getting laterals?

Yes, we did over -- we had 30 stages over 200,000-barrels and over 6 million pounds of sand for those 30 stages. And the micro seismic showed that we effectively fracked up about 400 feet and down about 400 feet.

How about laterally?

Laterally we went out 5,800 feet.

No, on the fracs?

Oh, I see about 1,000 feet out.

Thanks, and if you could comment a little bit on how you see the shale rollout throughout the basin, do you lose potential as you get close to the shelf margins and then also, is it hard to imagine that your 854-barrel a day wells at the northern end is going to extend, you aren't at the edge?

Most of our acreage in all these counties is in the deepest part and it's where the source rock is or the Wolfcamp. And the Wolfberry plays became famous on the fringes. So, obviously, they didn't have the source rock migrated up into the debris flows that people started drilling about three, four, five years ago on the flanks and that's where they coined it Wolfberry. You had better [prosty] and permeability. So, they all came from these areas in Upton, Reagan, Midland, and so on and that's really where the key source rock is where these horizontal wells are being drilled.

Okay, thank you very much.

Thank you. And next we'll hear from John Nelson with Macquarie.

All my questions have been answered, thank you.

Next we'll move on to John Herrlin with Societe Generale.

Three quick ones for me. With using sand, you're not worried about the anisotropic nature of sand like the sand breaking down versus ceramics for your fracs?

No, we haven't had any concerns about that so far.

Okay, that's fine. With the Wolfcamp, are you targeting in the middle Wolfcamp shale intervals or silty intervals?

Both. We have been using, we've been coining the term the Tippett Shale, but that's where we're -- it's a marker and that's where we're targeting a horizontal. We dropped it off the slides because nobody else is using that, but it's a marker that we use -- so but we are targeting both.

Yes, the Wolfcamp is a laminated shale/silty carbonate and a lot of different formations for a lot of different type of target zones, but intermingled.

Okay, great. Last one for me, with the deeper Spraberry wells that you were talking about, any co-mingling issues?

No.

From a production standpoint?

The only thing is we are actively, as we've stated before, pursuing the acquisition of some deep rights where it's necessary. We'll have about 75% of the deep rights where we could be drilling deeper wells in hand by the end of the year.

Okay, thank you.

Thank you, sir. Next we'll hear from Rehan Rashid with FBR Capital Markets.

Apologies for elongating the call here, but one big picture question on the Spraberry. Scott, we've talked about oil in place number before. Could you maybe give an update in terms of after having gone through to the Atoka and Mississippian, what would be the new guesstimate about the oil in place?

Yes, the last two years, excluding the deep and excluding the horizontal Wolfcamp, we were at 40 billion-barrels of oil in place. The horizontal Wolfcamp play and the Atoka and the Strawn are going to increase that significantly. I'm going to have to wait until Chris and his team come up with some new numbers, so it's going to go up substantially.

Okay, maybe a quick math. 20,000 locations, let's just say the 110,000-barrel EUR per well goes up to 150 by the time you're done averaging and combining, that gives me 3 billion-barrels of recurrable reserves if I just do that math and take a look at your '14 guidance of kind of production that you have to take the mid point of that. That still gives me 100 year RP off that pretty substantial growth from here. How can we think about maybe collapsing this RP ratio some more?

Obviously, the top wells, we make hundreds of thousands barrel a day wells and that's going to shorten the RP significantly at the horizontal Wolfcamp play. That's obviously the best place to do it with substantial growth plates there. Before that, we were in the process of just ramp, continuing to ramp up over the years and even past 45, and the thought was to continue to ramp up our rig counts over time on the vertical play. It's the best way. So, those are really the two best ways to shorten your RP ratio in this field.

Okay, so maybe I was headed towards revisiting the JV conversation, would that help take some money off of the table?

Yes, (Inaudible) I was asked that early on and at this point, we're not looking at it, but, obviously, it's always an option down the road so that's another option too.

Okay, thank you.

Thank you, sir. Next we'll hear from began Gabriele Sorbara with Caris and Company.

Just on NGL pricing, obviously, you've benefited this quarter. Can you give any guidance going forward on where you see pricing? Are we still going to get an up lift there at Mont Belvieu?

Yes, I think we'll continue to see. A lot of it depends on supply and demand fundamentals, but based on what we're seeing out of the petrochemical industry, I would expect we'll still see strong NGL pricing going forward.

Okay, great, thank you. Just back to the Eagle Ford, I appreciate the IP rates on the slide. Can you guys provide an EUR range for those three distinct areas you guys define in the presentation?

Well, we talked about that today. The ranges vary considerably. In fact you can look at some of the offset operators who are drilling oil wells into the West and there you're seeing 300,000, 400,000-barrel oil EURs and as you go into the dryer gas areas, you're seeing wells that make 7, 8, 9 BCFE mostly dry gas and in between you tend to see a combination. That's why we give a blended number that's incorporating all those data points.

Okay, thanks guys, appreciate it.

Thank you, sir. Next we'll hear from Joe Allman with JPMorgan.

Just a follow-up on the Spraberry. So, is the determinant for taking wells deeper, is it strictly the rock or do you factor in capital or are there other factors that determine whether you take these wells deeper?

It starts off with our geological team and mapping. There's been several deep wells drilled into the Atoka, in both Martin and Midland County, those are the two key counties where the deeper drilling is going on between the Mississippian, the Strawn, and the Atoka in those two counties. So, everything has been mapped, primarily based on deeper drilling and that's how we determine we're spreading our wells out in the Strawn. We have enough -- we drilled over 100 wells down the Strawn, so, obviously, we've got pretty good data now. We've only drilled three in the Atoka, as Tim mentioned. So, we just got to drill some more of the next 12 to 18 months to determine how big it could be, but so far we're three for three there and the wells are coming on much better than expected. In the Mississippian, we just did our first well, but there's a lot of offset data of other operators that have been going to it and so the next driver, we're getting better returns.

The focus, as Tim mentioned, is on the deeper drilling. So, we do get better returns there than we do just a straight Spraberry Wolfcamp and to the bottom of the lower Wolfcamp. So, we hope the deeper expands, the well costs do go up and it's getting up to about $1.9 million for those type wells and so -- but we're seeing much better and better results. And as Tim mentioned, we put in that 5.5-inch casing. A lot of our wells are coming in 80 to 100-barrels a day and just staying flat and we can't pump them off because we've got too small a casing, so if we go to 5.5 inch casing, I would anticipate higher rates in these wells and more of a hyperbolic decline curve. Right now, some of these wells aren't even declining. We can't pump the wells off some of these deeper wells.

Okay, so just to clarify, so is there any where you think you've got the Atoka or the Strawn or the Atoka, Mississippian, you're going to take it deeper just because the economics?

Yes.

And then those percentages that you show on slide 9, are those percentages, the percentage of wells you're going to drill to those deeper formations in 2012, are those -- is that the best guess of the percentage of acreage that you think is perspective because for example, the Strawn I think in the past you've said 25% to 50% of your acreage you think is perspective for the Strawn?

Yes, the acreage is a better -- we aren't -- it's a different percentage and so we're not like the Atoka is 25 to 50 so we aren't taking 50% of our wells down. So, we need more data, so the Atoka has gone from a few wells to a lot more, and so as we get more results from the Atoka, then you would see going into '13 most likely there would be a lot more wells at a higher percentage going to the Atoka.

Right, but say like in the Strawn for example, so your slide indicates you're taking 25% of the wells down to the Strawn, whereas in the past you said that you think 25% to 50% of your acreage has the Strawn, so what's the difference there?

We said 40% of our acreage is perspective.

Okay.

But there is a percentage of our wells that we are not completing in the Strawn, because there's no porosity, okay? So, not every well we take to the Strawn -- the Strawn is more structural, it's got to have porosity. The Atoka, we anticipate to be much higher success rate than the Strawn, so that's the difference so we just need more data. It will take us a got two to three years in each of these intervals to determine -- eventually you'll see us most likely match up more with the percent perspective acreage probably about two to three years from now on slide number 9.

Got you, okay, got it understood. Thank you.

Thank you, sir. We'll take our final question from Dan Schniedwind with AMI Asset Management.

Hi guys, congrats on a good quarter. Quick question for you from a credit perspective, you're really starting to look like an investment grade company. Have you talked to any of the credit rating agencies about possibilities what you would have to do to achieve that? And I know they are usually asleep at the wheel on these things and the last I realize when you should be, but has there been any communication there?

Yes, we have constant communication with the rating agencies and have -- we agree with you that we think we are heading to or already at an investment grade credit. So, we're just waiting until we have more results is really what they're waiting on, so I think over time, we expect to continue to head that way.

Okay, great.

Thank you and that is all the questions we have in the queue at this time. I'd like to turn the conference back over to management for any additional or closing remarks.

We appreciate everybody staying on longer, great questions and hopefully you got the right answers, if not you know where to get us here in the office. Look forward to seeing everybody on the road. Again, have a great fourth quarter coming up.

Thank you and that does conclude today's conference. We thank you for your participation. You may now disconnect.