先鋒自然資源 (PXD) 2010 Q4 法說會逐字稿

Welcome to Pioneer Natural Resources fourth-quarter conference call. Today's call is being recorded. 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 their comments today. These slides can be accessed over the Internet at www.PXD.com. Again, the Internet site to access the slides related to today's call is www.PXD.com. At the website, select Investors, then select Investor Presentations.

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 earnings release on page 2 of the slide presentation, and in Pioneer's public filings made with the Securities & Exchange Commission.

At this time, for opening remarks and introductions, I would like to turn the call 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 am going to briefly review the agenda for today's call. Scott is going to be up first. He will review the financial and operating highlights for the fourth quarter of 2010, another solid quarter for Pioneer. He will then comment on the Company's strong reserve performance for 2010, and our capital program for 2011.

After that, Tim will update you on our drilling results and plans, particularly focused on the Spraberry, the Eagle Ford Shale, and the Barnett Shale combo play. Rich will then cover the fourth-quarter financials in more detail, and he will provide earnings guidance for the first quarter. And after that we'll open up the call for your questions.

With that, I will turn the call over to Scott.

Thanks, Frank. Good morning. Appreciate the time to listen to our quarterly call. Again, as Frank said, we had a tremendous year last year. We'll talk about also we had a tremendous fourth quarter. On slide number 3, we had adjusted income of $59 million, or $0.51 per diluted share. That excludes a net gain from unusual items of about $106 million after-tax or $0.87 per share. It also excludes unrealized market-to-market derivative losses of $85 million after-tax, or $0.71 per diluted share.

Fourth-quarter production came in at 117,000 barrels a day equivalent. Taking out Tunisia, we had 111,000 barrels a day, excluding discontinued operations. We achieved our production growth target of 10% that we set out over a year ago versus fourth-quarter 2009.If you back out Tunisia during that timeframe, we achieved a growth target of 11%.

Spraberry production obviously is way exceeding forecast with the new zones being opened. We're currently running 30 rigs, expect to be at 35 rigs by mid-year. What's most important with the results in Spraberry, the fact that we feel like that we have enough history now to significantly increase the type curve. 40-acre type curve EUR has been increased from 110,000 barrels of oil equivalent to 140,000 barrels of oil equivalent, based on several months of history, which Tim will go over from our 2010 drilling program.

In addition, the Eagle Ford Shale has been ramping up significantly as expected. We exited 2010 at a net 5,000 barrels a day equivalent. When you look at it on a gross basis in a period of nine months, we essentially hit 100 million a day equivalent in a nine-month start-up period. So really congratulations to our Eagle Ford team. We'll continue to ramp-up significantly over the next several quarters. We're running seven rigs, expect to be at 12 rigs by mid-year. We have three central gathering plants online, two more on by March, and three more by year-end in 2011.

In addition, we're continuing to expand our vertical integration, obviously based on the quick payout that we're seeing, both in Spraberry, Eagle Ford, and Barnett combo will be over 200,000 horsepower in those three areas combined in the Company in regard to our frac stimulation horsepower.

In addition, as we have delivered last week, in regard to our press release on finding costs and reserve replacement, delivered 363% reserve replacement. That improved reserves of 163 million barrels, including over 100 million barrels from drill bit additions, a 12% increase year-end 2010 reserves, we're now over 1 billion barrels compared to year-end 2009. Reported 2010 drill bit finding costs, under our target of $10 to $15, at $9.96, excluding price revisions.

Also, we accomplished our financial goals, moving our debt-to-book significantly down. Debt-to-book capitalization decreased from 43% year-end 2009, to 37% at year-end 2010. Obviously with the next comment about Tunisia, we'll be significantly down again by the end of first quarter based on that sale. We announced the sale of Tunisian subsidiaries for $866 million. Everything is on track for a closing by the end of first quarter. Proceeds, obviously, we'll talk about that, will be redeployed to core US assets, primarily in Texas.

Slide number four, increasing our annual production growth rate, obviously, from 15%- to 18%-plus, compounded growth rate for that three-year period 2011 to 2013, primarily increasing activity in the Eagle Ford, the Spraberry, and the Barnett combo play. Again, we achieved our 10% production growth rate over the last 12 months at 11%, reflecting if you back out Tunisia. We're forecasting annual production growth of 15% to 19% from 2010 to 2011. And again, we're increasing our compounded annual growth rate, CAGR, for that 2011 three-year period from 15%-plus to 18%-plus.

Liquids production continued to increase. It will go from 44% in 2010 to 55% in 2013. On the chart below, again, exhibits both our 10% and 11% production growth rate, reflecting Tunisia as discontinued ops on the left side. And in addition for 2011, the 15% to 19% correlates to 125,000 to 130,000 barrels a day equivalent. If you look at the first quarter, obviously we do have -- Tim will talk more about it, but delayed completions in regard to the Eagle Ford until we get our own frac crews and dedicated frac crews coming into the play in March. And also we have had some weather down-time over the last week, which is not reflected in those numbers. Again, over that three-year period, we're looking at 18%-plus, driven primarily by the Spraberry ramp-up and the Eagle Ford ramp-up.

Slide number 5, obviously very strong 2010 reserve additions. We ended the year a little bit over 1 billion barrels. As I mentioned already, we've added 163 million barrels, 100 million from drill bit additions, primarily from Spraberry, Eagle Ford, Alaska and Tunisia, a 12% overall increase from year-end 2009 to 2010. We did have positive revisions, primarily from oil in the Spraberry. We did have some revisions in Raton, primarily due to the improved differentials, but not as much gas price for the differentials over the last 12 months. All PUDs scheduled to be drilled within a five-year period. Obviously the cash flow is expected to be sufficient to be able to drill those up. In addition, all Spraberry, Raton, and Eagle Ford PUDs are within one offset of the PDP location.

Table off to the right, obviously Spraberry had the big increase, and you can see the line-up. Obviously huge more potential of booking, both primarily in Spraberry, Eagle Ford and Barnett over the next several years. This reflects year end pricing of about $79 oil and $4.37 gas. Slide Number Six, Strong 2010 F&D Performance, again we had F&D cost $9.96, excluding price revisions below our targeted F&D cost of $10 to $15. Also all in $7.30, including price revisions.

Reserve Mix state very constant compare to last year US 97% US, 56% liquids. Proved developed and PUD ratios stayed fairly close to what has happened last year. Proved reserves production 22 years. Proved developed reserves to production ratio 13 years. Going in to our capital budgets for 2011 on slide number seven, we're starting out the year with drilling capital of $1.6 billion. Obviously the big ramp up is in Spraberry by going up to 30 to 35 rigs during the year, be at $1.1 billion for Spraberry.

The Eagle Ford we will still be about $110 million, obviously this is net of the carry, Eagle Ford is obviously still our second biggest activity, but because of the carry, it's only reflecting $110 million Eagle Ford Shale.. Two rig program in Barnett Shale Combo of $170 million.

Alaska, a one rig program up there continuing at $115 million. And $120 million in other includes land capital obviously for existing assets and preserving leases. Also vertical integration of facilities, we're spending about $200 million.

Obviously that will complete most of the orders that we have made in both 2010 and 2011 primarily for frac equipment and pull-in units, obviously that number will slow down going into 2012 considerably.

Capital program funded from operating cash flow of $1.4 billion based on the current strip as shown in the graph and also redeployment of about $400 million of Tunisia sale proceeds. Slide number eight shows the Operating Cash Flow Growth, we're increasing that also up to a 25% CAGR growth rate with the result of our 18% plus production growth rate CAGR during that same time frame.

We're going up from about $1 billion in 2010 up to $2.3 billion in 2013, so a 25% CAGR. Obviously as shown in the graph, the first year does not include proceeds from deepwater Gulf of Mexico and insurance recoveries during that year of about $300 million. This is based on the February strip pricing and also includes our hedging program as of February 4.

Finally on slide number nine, Investment Highlights, Pioneer is fortunate to have over 20,000 drilling locations in liquid rich areas, primarily in the Spraberry, Eagle Ford and the Barnett Combo play in Texas, very low risk resource plays. Obviously we are accelerating activity in really all three areas, primarily in the Spraberry and Eagle Ford.

Redeployment of our proceeds from our Tunisia sale allows further acceleration, again, increasing our target from 15%-plus to 18%-plus over that three-year period, and a cash flow target up to 25% during that same three-year period.

We're continuing on the recent activity, you can look back in our hedging schedule. We have started putting on some more hedges in 2014 in regard to oil. The call position on the upside has gotten up to $130 to $135, that gives us upside protecting -- trying to lock in potential flow of around $90, so we've added some there, but great hedging positions for years 2011, 2012, some in 2013 and 2014.

And then finally, obviously the Tunisia sale continues to improve our strong financial position. Our debt-to-book numbers will continue to move down significantly over 2011.

Let me now turn it over to Tim.

Thanks, Scott. And as Scott mentioned, our Spraberry drilling acceleration is paying off handsomely in terms of production growth. And for some time, we've been alluding to an upward type curve adjustment for our vertical drilling program, and I have a couple slides to talk about that. The result, really, of the fact we've been deepening the wells in our 2010 campaign into the Lower Wolfcamp, and also completing the interbedded shale silt intervals through all of that campaign.

What you see on slide 10 is the same wells that we had in our last quarter report just updated for production for 2010. Remember, this re-vintaging of wells all starting on the same point to determine the effect of the incremental deepening and interbedded intervals. You can see on the graph clearly we have excellent empirical data that shows we've had approximately a 30% increase in cumulative production for those wells during the first part of 2010.

As a result of this data, and the fact now that we have several months of history, we're confident now to depict, as shown on slide 11, the new Spraberry 40-acre type curve. It is now shown to be approximately 140,000 BOE in the green line, the result of which is principally related to deepening the Wolfcamp as I mentioned, and completing other zones in interbedded shale silts. That said, it is also important to note that this graph does not include any contribution from Strawn, where we have been completing quite a number of wells in 2010, or the Deeper Atoka, that's under study as we speak. And it is also important to note that we have not yet incremented our resource potential numbers for this new type curve, which we plan to do here shortly.

Turning to slide 12, this is a project update for what's happening in the Permian Basin. Our objective for this call was to have production data for our first horizontal well. We have had some recent bad weather that Scott alluded to that's been hampering the efforts to get the production going from this well. We are currently flowing the well back, and I anticipate that we'll be having production data that we'll be able to share with you when it is in sufficient state to be able to do so.

We also have a second horizontal well we're just in the process of starting to drill the horizontal lateral. That's in the Lower Wolfcamp shale section. We should have data regarding that well results sometime during March. We'll evaluate those wells, and I anticipate we'll be planning some additional horizontals depending upon the results from those wells when those data come in.

Our water flood project's going very well. We're now injecting about 4,100 barrels a day, and importantly, we're starting to see some early results, and they look very encouraging. What we're seeing is a flattening of the production decline curve you'd expect from these wells, which is the first sign that you have a positive result. I would say it is still early, but all signs are positive on the water flood. We do anticipate a significant increase in production from the flooded zone in this case, the Upper Spraberry. And to the extent it works, we have identified already specific places where we could implement new water floods in future campaigns.

On slide 13, in Permian Basin, of course, we are going much further towards vertical integration. We have a long history of vertical integration in the Company going back to the Evergreen days in the Raton Basin. The objective, of course, is to control costs and to execute on this accelerated plan in the Permian Basin. And toward that end, we have 12 Company-owned rigs today. As Scott has alluded to, we also are expanding our frac fleets. We now have two additional fleets coming in, one in the second quarter and one in the fourth quarter, to add to the three fleets we already have operational.

We also have two dedicated third-party fleets that will be operational here shortly, and these will be enough I think to deal with what's a ramped-up drilling campaign in 2011. Importantly, we have most of our other supply in place from our service companies, including sand, tubulars, and pumping units, as well. And we have, really, in various different ways, increased our vertical integration including pulling units, fishing tools, for instance, and we plan to continue to do so.

And it is important to note that the vertical integration, we feel like, will be able to save us something like $500,000 per well as compared to simply doing everything with third parties. And so when you look at our 2011 blended cost of wells, including the wells where we'll be using our own services and third-party services, we anticipate the costs of the wells will be about $1.4 million to $1.5 million. That is really a combination of deepening the wells, and creep we have seen over the last 12 months. That said, because of the deepening of the wells and the increase in the type curve, we still see very strong economics on these wells, something like 45% IRRs before tax.

If you turn to slide 14 then, the results of this acceleration is leading to very significant increases in our production, exceeding our plans. If you look at the fourth-quarter results, for instance, we produced about 38,000 BOE per day net, and that's up about 9% compared to the third quarter. Importantly, it is also about 2,000 barrels a day over the forecast we had earlier last year. And as a result of the fact that we're deploying some of the proceeds from our Tunisia divestiture into the Permian Basin to further accelerate it, as we now move from 30 to 35 rigs at mid-year, we're now forecasting 2011 production to be higher than originally thought, in the neighborhood now of 42,000 to 46,000 BOE per day. And as you look forward, of course, we're estimating 40-plus rigs in the next couple of years, and you can see the dramatic ramp-up of production, with a new CAGR for Permian operations now seen to be approximately 25% through 2013.

Turning to Eagle Ford, which is on slide 15, our acceleration in the play continues, very pleased with how that's going. Scott has already mentioned the fact that we have seven rigs running as we speak, going to 12 rigs. Importantly, we have done a great job so far of reducing drilling time and improving completion techniques. If you look at the current number of days drilling, and any other measures similar to that, such as cost per foot, we are exceeding what we first began in the play by some 20% to 30% on all of those metrics. So our drilling team has done an excellent job, even in the early stages of this play, of driving down costs and improving efficiencies.

And similarly, we're doing work regarding improving completion techniques, such as using our microseismic to reduce the number of stages pumped per well, and the result is we've been able to keep well costs still in that range of $7 million to $8 million despite the very significant increase in completion costs in the play. And the result of which is still extremely strong economics, that's both in the high-condensate yield areas and the medium- and low-condensate yield areas where we're doing most of our drilling.

We've drilled 41 wells. We have 21 on production, and three wells waiting on hook-up. We have had some delays in the third-party fleet that was dedicated late last year. We anticipated that fleet to be in place in the early part of this quarter, now it is expected to be operational only late in the quarter, and so that's delaying some of our fracs.

That said, we have acquired two Company-owned fleets, which are now being placed on schedule, one in the second quarter and one in the fourth quarter. And importantly, as we drill up and down the play, preserving our lease-hold, we're seeing really predicted well performance continuing, which is a very important fact that we're seeing consistent results as expected. Three central gas processing facilities are online, we have two more expected in March. We've had slight delays on those, but expect those to be in place shortly, with three more due by the end of 2011. And the result of which you see on 16, is a substantial ramp-up also in the Eagle Ford Shale production, again, a portion of the proceeds from the Tunisia divestiture will be used to even further accelerate the growth there, just as we're doing in the Permian Basin.

We did meet our forecasted exit rate of 5,000 BOE per day, Scott already alluded to that, and we're increasing the 2011 forecast in response to that acceleration up to 12,000 to 15,000 BOE per day net. And then furthermore, as we go to an increased rig count up to 14 and 16 rigs, you can see the dramatic increase in production coming out of the Eagle Ford Shale development. So it is going exceedingly well, and we're looking forward to continued rapid growth in this play as we go through the next several quarters.

On slide 17, a third leg of our Texas-based liquids development is in the Barnett Shale combo play. We have about 65,000 net acres in the play today, and two rigs running. Again, I would have liked to have been able to report a lot of details surrounding this production, but we're just flowing back our first three completed wells. These wells are all being drilled on pads, and as such, we're completing all the wells simultaneously on pads only after all the wells are drilled. So that's why we don't really have any significant results to share with you yet, but as soon as we do, of course, we'll come out with some information as to how these wells are performing. Expect first production here, as I said, as we finish the flowback of these wells.

They're generally drilled with 3,500-foot laterals, and we're able to keep the costs under control at about $2.8 million, and the result is that our estimated returns look very strong, at about 45% before tax. We do have one additional fleet coming in here for fracking the wells that will be in the second quarter or so. And so we're looking forward to these well results as we continue to accelerate and execute on our plan.

Just a couple more notes that we don't have slides for, but nonetheless deserve some comment. In Alaska, we have alluded to some operational issues we had during the quarter that were really related to third-party service disruptions. We had some compressor outages, and some interrupted supply of natural gas and water from third parties, which limited our operational results, but our main focus this winter is actually on the Torok drilling campaign. We are going to be drilling and fracking two horizontal Torok wells to match up with the one we already have on production, and the idea is to get a view as to how well these would shape up for potential larger development in the Moraine/Torok area south of the Oooguruk Island. So these wells are important to watch in terms of the future potential for a project on the North Slope.

I would also be remiss if I didn't mention some of our other cash-producing assets. These assets are not getting a lot of capital today in today's gas price world. However, it is the case that due to our operational teams in Raton and South Texas and our Mid-continent areas, their production has remained essentially flat in the fourth quarter due to attention to detail in our production operations.

So I am going to stop there and pass it over to Rich for a discussion of fourth-quarter financials and his outlook for the first quarter.

Great, thanks, Tim, and good morning. Turning to slide 18, fourth-quarter earnings, net income attributable to common stockholders was $80 million, or $0.67 per diluted share. That did include unrealized mark-to-market derivative losses, primarily related to the rising futures curve for oil prices of $85 million, or $0.71 per diluted share. And so adjusting for those items it was $165 million, or $1.38 per diluted share.

Listed on slide 18 is a number of unusual items that I am not going to go in detail here. We did put a fairly detailed description in the press release, so I encourage you to look at that, that explains each one of those. But I think in total when you look at that, you adjust our $165 million down to $59 million of what we would say would be a pseudo-clean earnings of $59 million, or $0.51 per diluted share.

Turning to slide 19, what we did here was in the middle column, I'll draw your attention to, is our adjusted results including Tunisia, obviously for financial reporting purposes we put that in discontinued operations, but we included it here to show how we did relative to the guidance we put out coming into the quarter. And so as you go through the middle column including Tunisia but excluding the unusual items, you can see that we did well relative to the guidance we put out earlier in the quarter.

Turn to slide 20 and look at price realizations. The bars show what our realized prices were before hedging and BPP impacts. And so you can see that oil prices were up almost $80, up 14% relative to the third quarter, NGL prices were up 23% from the third quarter to $41, and gas prices continued their weakness and were down 11% to $3.76. When you look at the table below, you can see that we still benefit from our strong derivative position that Scott talked about for oil. We added $1.32 per barrel from our derivatives during the quarter, and for gas we added $1.28 to our gas price based on our derivatives.

If you turn to slide 21, look at production costs for the quarter were $10.94. That did include the benefit of a recovery in Alaska of some processing fees, that there was a retroactive law change in Alaska. And so we have the positive benefit of $1.02 per BOE in the quarter there. We also have a benefit of $0.43 in ad valorem tax we had accrued throughout the year, what we thought we were going to end up owing in the fourth quarter. We got the actual bills in, and we were a little over-accrued, so that was a positive effect of $0.43 per BOE in the fourth quarter.

Turning to slide 22 and first quarter guidance, as Scott and Tim both mentioned, this guidance doesn't reflect the weather we had last weekend, but if you look at production for the quarter, 114,000 to 118,000 is what we're projecting. That's compared to the 111,000 equivalent basis, excluding Tunisia for the fourth quarter, production costs of $11.75 to $13.75, very similar to where we have been in past quarters.

As you go down the list, everything is very similar to where we have been in past quarters. A couple things I will point out is on cash taxes, with the sale of Tunisia, that was a place that we were paying cash taxes, so the only place we're really going to be paying cash taxes for 2011 is in South Africa, and so this range reflects South Africa cash taxes primarily. And because Tunisia was a higher effective tax rate jurisdiction, our effective tax rate is moving down from what used to be typically 40% to 50%, to 35% to 45%.

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

The question-and-answer session will be conducted electronically. (Operator Instructions)We'll take our first question from Mitch Wurschmidt from Keybanc.

Hi, guys, congrats on the quarter. Just a couple questions. Can you give a little more on the -- if you are going down to the Strawn or the Atoka, deepening some of those verticals, what's the incremental EUR you get and the incremental well costs?

This is Tim. I will answer that question for you. First of all, as we have done quite a bit of drilling in the Strawn in 2010, in fact we drilled 88 wells in 2010 that targeted the Strawn, about half of those have been put on production by year-end. And so we have data probably on about 20 wells having been completed and produced for enough months, and that would tend to show contributions in the neighborhood of 20 to 40 barrels a day increment, potential EURs, probably in the same range, 20,000 to 40,000 BOE.

Okay. What's the extra cost I guess to pick that up?

Approximately $100,000.

Okay. Great. And then on the EURs you did give, though, are you seeing -- how are the wells trending along that new curve you gave? Are you seeing much variability or are you seeing -- I guess is it out performing that curve even? Is there much conservatism built into that?

Well, I think we're trying to be conservative with everything we put out, so you can expect that in the future, as well. But suffice it to say we -- there is a statistical aspect to this, some wells are slightly better, some are slightly worse, but overall that's just depicting the current well count. But looking forward we anticipate we're going to continue to try to make the jump steps or jump shifts in production by this technology application.

And I just wonder, I know you didn't give any -- on the Wolfcamp Shale is still flowing back -- or the Wolfcamp carbon, I guess, is flowing back, but on the shale, can you talk a little bit about attributes of it, or lithology-wise, is that comparable to some of the other plays and are you seeing shale plays?

I am not a geologist, unfortunately, so I can't really answer that question. But what I would suggest you do is call in to our IR team, they can give you all the details on the rock quality.

Okay, thanks. I guess the last one, just in terms of you guys getting cash-flow-neutral, can you talk about -- obviously spending to accelerate on these plays, can you talk about when you're looking at getting cash-flow-neutral again?

Yes. We are -- the $200 million we're spending on vertical integration will go down significantly going into next year. Land activity on Other will obviously go down going into 2012, so obviously the overspending using the Tunisia cash this year will significantly go down going into 2012 and 2013.

Okay. Great. Alright. Thanks. I will jump back in the queue. Thanks, guys.

We'll now take our next question from Scott Wilmoth with Simmons & Company.

Hi, guys, just looking at your 2011 CapEx budget, what assumptions are you guys currently making for well costs? Are you guys assuming current well costs or some continued inflation throughout the year?

I think we already have seen, Scott -- this is Tim -- some creep in the beginning here in the first quarter, but it is starting to level off, so I think our plan right now is to use that $1.4 million to $1.5 million average as our blended Permian costs, and then $7 million to $8 million gross costs on Eagle Ford wells. I think things are flattening out and so I anticipate those costs will be good for some time.

That $1.4 million to $1.5 million in the Spraberry, does that assume deepening to the Strawn and Atoka?

Most of the wells, in fact probably half of the wells, will be drilled into the Strawn, but it does not at this point include any Atoka, particularly speaking. That said, we are going to be doing some Atoka tests this year, which will have us deepening some wells that really are more related to R&D for the Atoka.

And then just you'd mentioned earlier the $100,000 to deepen to the Strawn and the Atoka. Can you comment about the cost creep, what -- how much of that has been and where have you guys seen that creep come from?

Well, Permian Basin has not had the kind of cost creep we have seen in the Eagle Ford Shale, for instance, but if you look at, for instance, LOE in the Permian Basin increased about 10% during 2010, mostly due to increases in things like diesel and labor costs and so on.

Where we did see a significant increase was in pumping services, just as had been the case in the Eagle Ford Shale where you had a pretty significant dramatic doubling or a little bit more than doubling of completion costs there, so that's where the vast majority of the cost creep has come from.

That said, at the same time, when the rig rates were set in early 2010 for last year, they were set at extremely low prices coming out of the downturn. We have seen about a 20% bump in rig costs for 2011 that is associated with most of our rigs, and so accordingly it is a combination of those that landed us at the new run rate.

Okay. Lastly, just on the horizontal Wolfcamp, the one well that you have drilled, and obviously they're still flowing back, what was the drilled and completed cost of that well and can you just speak to how the drilling went versus expectations?

The costs of the well -- of course, we're doing quite a bit of testing on this well, and wouldn't anticipate this being the development costs of a well, we're more in the development mode, but this well is going to cost probably roughly about $6 million. What was the second part of your question again?

Just how the drilling went, and then also maybe the completion technique you guys used, how many stages, lateral link, things like that?

It is about a 4000-foot lateral, 14 stages, a traditional Permian-type completion from the standpoint of horizontal drilling in this case, so it is a plug and perf.

Okay. Thanks, guys.

Our next question comes from Brian Singer with Goldman Sachs.

Thanks. Good morning.

Hi, Brian.

In the Eagle Ford, can you just talk about any changes you're seeing to how long it is taking you to get wells drilled and then completed? And then could you also give us an update on the -- how much is left in the Reliance carry and when you'd expect that to run out now that you've increased your drilling plans?

Well, first of all, on Reliance, I anticipate that that carry probably is done early part 2013, late 2012, and so I think that is going exceptionally well. In the Eagle Ford -- let's see, I got it backwards. What was your first question again? I got them mixed up.

Yes, are you seeing any changes in the Eagle Ford to drilling -- to the amount of time it's taking you to drill and complete wells, the time and the cost, but particularly the time?

Let me give you a little bit of a recap of what I said earlier, which is on the drilling -- time drilling and the costs related to drilling, we're seeing very dramatic improvements in efficiencies. And this is measured in however you want to measure it, cost per foot, dollars on each well, days. And we have seen reductions in the neighborhood of 20% to 30% or more since the Eagle Ford campaign began, and that simply is because we're going up the learning curve and are doing a good job of improving efficiencies in the field.

That said, at the same time during 2010, as you know, there is some dramatic increase in the completion costs --100%. And as a result, we're seeing the total well costs being similar to where they were in 2010, the drilling component of which is substantially down, the frac component of which is up.

And so I guess from here, when you look out a year out, how long do you think it would take to drill and complete an Eagle Ford well versus where things have improved to today?

Today we're probably about 20 days to drill the wells. One of the issues I mentioned earlier is the fact that we are waiting on completions on some wells related to the fact that our third-party frac fleet is not going to be here until the latter part of the third quarter. So -- but the completions are just simply a matter of days.

So one thing we're trying to do, of course, is reduce the number of days we're on these wells. And I think when all of this is factored in and when we start getting the proper number of frac fleets out there, both Pioneer and third-party, that we'll be able to drill 10 to 12 wells per rig, so we'll be on and off these wells typically in 30 days, counting door-to-door.

Great. Thanks. Lastly, just looking at the -- your decision to sell Tunisia, when you think about the next couple of years out, and you look at the strong growth coming out of the Eagle Ford, the Spraberry, and potentially the Barnett combo, do you see increasingly your other base assets in the Mid-Continent, Raton Basin, et cetera, Alaska, as potential candidates for asset sales and how do you think about that going forward?

Brian, our cash cows at Mid-Continent and Raton have had very little decline. They will continue to be cash cows, a little bit of the budget will go into -- the Other category on my slide will go into Raton, a little bit into Mid-Continent maintenance capital, to keep -- to reduce decline down to probably 3% to 4% from about typically 6% to 8%. Alaska will continue, as Tim mentioned, the Torok is a 50 million-barrel discovery we made about a year ago. We need to prove that discovery up, so Alaska has a lot of upside, we need to evaluate it over the next couple years. So right now we see no other assets for divesture.

Great. Thank you.

We'll now take our next question from Brian Corales with Howard Weil.

Hey, guys. Good quarter. A couple questions on the Eagle Ford. Once you get the Company on frac fleet, what would that AFE look like?

Well, I think it is the case that our current completion costs in the Eagle Ford of about $5.5 million, we think it is very possible that we could be able to frac these wells ourselves for $1.5 million to $2 million less than that. Now of course on top of that you have the drilling costs, so a $7 million to $8 million current AFE you drop in the neighborhood of $1.5 million to $2 million.

Okay. That's helpful. Also, you talked about the efficiencies in the Eagle Ford and obviously the improvement on the production side. Is any of that because the well performance is better than you all previously estimated? I think you all were at 5 to 6 Bs. Is that trending on higher than that or where does that sit today?

I think we feel it has been very consistent up and down the trend, and of course we have a substantial amount of 3D seismic, as you know, and have done a lot of drilling out there when it comes to even our prior Edwards campaigns. So we have a very good understanding about the gradient as you go from the oil window into the condensate window and into the gas window.

I think we can very clearly, and in fact we have done it exceptionally well, predict what well performance is going to do, and the well has have been very consistent with those predictions, which is a very positive thing because you have a substantial amount of aerial extent in this play. If you feel like you had predictable outcome through the acreage, that's a very big positive.

Okay. One final more housekeeping item. Do you all have the future development costs for your reserves?

We can get it for you. I don't have it here in front of me.

That's fine. I will ring you offline later. Thank you.

Our next question comes from Leo Mariani with RBC.

Good morning here, guys. You guys talked about a blended well costs of the Spraberry of about $1.4 million to $1.5 million. Just to clarify, can you give us what you think the number is with PXD equipment versus third-party?

It is about -- we would say about $1.3 million or so for a PXD 100% well, and it is probably $1.8 million door-to-door, all third-party equipment.

Okay. Got you. And I guess, just sticking with the Spraberry here, I think you guys have stated in the past that you felt as though the Strawn was prevalent at roughly 30% to 40% of your acreage. Just wanted to see if that number is accurate, and then I also just wanted to check in to see how much of your acreage you thought the Atoka was prospective?

Strawn we still believe is in that neighborhood. I think it is the case that we expect to complete the Strawn, for instance, in our 2011 program in at least 25% of the wells, so I think that number is still good, 30% to 40% of the acreage in the Strawn.

I will tell you on the Atoka we're in early days of study. There is some data that suggests that it could be at least potentially prospective for upwards of 25% of our acreage. Of course it will involve deepening of the wells, so we will be doing a number of tests, at least a few tests, during 2011 to get that answer for you.

Okay. In terms of your Spraberry here, you guys talked about a 30% increase in EURs here by adding some additional zones. What did the third party engineers give you guys in your year-end 2010 reserve report? Did they give you that much of an increase as well on some of your wells here?

I think quite a large number of our wells are just producing wells, so of course that's a lot of things that they're auditing, but we have not really done much of a bump yet when it comes to incremental EUR for the new type curve.

Okay. So I guess that stuff hopefully will show up in your reserve report during the course of the year as the third-party gets more comfortable, to be reasonable?

This is both internal and external, that's right, as we now begin to show even more data, we'll be confident we'll be increasing that through time. It is just it's not yet showing up in our reserve data.

Got you. Okay. Just jumping over to Tunisia, have you had any discussions with OMV regarding the asset sale here? Obviously there was a regime change over there, and have you talked to those guys, that seem to be potential issue at all?

No. We still expect, Leo, to close in the first quarter, so things are very calm over there now, and they're moving to a more democratic country, so it is probably very positive for OMV.

Okay. Thanks, guys.

We'll now take our next question from Gil Yang with Bank of America/Merrill Lynch.

Good morning, everyone. Could you talk about with the horizontal drilling that you're doing, if that's successful and you want to transition to more of a horizontal program, what is the availability of the equipment that you need to do that?

Based on these two wells, obviously we anticipate probably to drill some more. We're also -- the team is looking at drilling probably our best zone, we call it the Joe Mills zone, in the Spraberry. They're picking out a candidate now. So we'll put one in the Spraberry. If you recall, we talked about doing some horizontals about 15 years ago, and in the Joe Mills Spraberry, the fracture technology wasn't there. So we're going to go back -- it holds most of the oil in the Spraberry, so we're going to go back and try that one.

And obviously it will be a game changer for the entire trend because there is not enough horsepower out there to get these wells the type frac job they need and there is not the type of rigs to drill horizontal, so a lot of our rigs can be modified if needed. Probably have to order more frac equipment if it happens, but I see that taking probably a good couple years before we make that decision.

So we're going to drill probably a few more later this year, a few more going into 2012 to test both the carbonate and the lower shale zone, and then as I said we'll put one into the Joe Mills Spraberry.

One note, we do have, out of our 30 rigs, we have about four rigs that can drill horizontal wells that we're talking about as we speak in our current fleet.

Okay. All right. So you don't need any immediate change in the material that you have there?

Correct.

Scott, you said that you would drill into the Joe Mills Spraberry. Is that down-spaced enough on a vertical sense that creates difficulties in you accessing it horizontally?

No. We still have over 9000 locations on 40s, so basically we're finding out that there is a lot of oil in place. And so we still have some 80s, too, so your well may not be quite as long, your frac length, but we'll definitely try it, don't see any issues there.

Okay. Great. And can you -- if you go to -- what have you done with 20-acre down-spacing and what would the type curve -- if you have 140,000 BOE EUR for the 40-acre type curve, what would the 20-acre type curve look like?

Yes, Gil, this is Tim. Just to give you some data on that, we did drill 17 20-acre wells last year, and several of those were done in the fourth quarter. So I only have production data for eight wells, which I would not consider a statistical sample size to speak of.

But that said, what we're seeing from the 20-acre wells is clearly production above the 110,000 BOE type curve. We're trying to asses exactly how far it is, whether it equals the 140 or slightly below the 140, so it is a little bit hard to tell from eight wells, but it is clearly over the 110,000-barrel curve, which is very positive. We do plan to drill another 20 or 30 20-acre wells this year, so we' have a continuing increasing data set as we go forward.

But it could be as high as 140, so possibly you're seeing no interference?

I anticipate the interference would not be seen for some time. We have such low permeability rock here, that in case up to 20-acre wells would not necessarily immediately affect -- offset 40s. But that said, I anticipate that these are going to be economic 20-acre wells, needless to say, to the extent they'll produce significantly over the 110,000 BOE type curve.

Okay. Alright, great. Last question is, just in terms of the going back to the PUDs, it sounds like you put some Raton PUDs back on the books and it sounds like you specifically have some plans to drill those in the next five years based on the current cash strip. Is that fair to say?

Yes. As I mentioned, Gil, at strip pricing and at current gas price, it is very economical. It is not as economical obviously as some of our oil plays, but it is important to maintain the asset over the next several years and reduce decline. But it is minimal capital, probably something in the neighborhood of about $30 million to $40 million per year.

Okay. And I'm sorry, that will start this year?

Yes.

Okay. Alright. Thanks a lot.

We'll now take our next question from John Nelson with Macquarie?

Thanks. If I could just piggyback actually off that last question. On the 20-acre down-spacing Spraberry wells are you using any completion differences or is everything still the same?

Well the only thing that's different about these 20 acres as compared to some of the prior campaigns, is they're also being deepened due to the Lower Wolfcamp. And my guess is that's why they're showing production in excess of our old type curve.Other than that, the completions are identical.

Great. Thanks. And then just switching over to Eagle Ford, just curious if the change in well design, is that being done purely to restrain costs or is that more to keep production in line with take-away capacity? Because I would think that marginal returns would still be attractive enough that the additional stages would be warranted.

Well, the well design, of course improvements are related to really efficiencies, operational efficiencies, rig drilling efficiencies and so on. So we're not really doing a lot of changes in well design. Of course, we're tweaking at the margin on well design, and it is actually improving.

But the completion techniques are really oriented towards trying to determine whether or not we need, for instance, 14 or 15 frac stages or whether we can get by with 12. It is simply a matter of costs. The way we're determining that, of course, is through microseismic techniques. So really it is at the margin. I wouldn't consider it a significant change in how the wells are being drilled or completed as much as it is attention to detail.

Great. And then where would you guys say the marginal dollar goes in your capital budget if oil prices were continuing to stay strong, or stronger than you've modeled thus far?

Cash flow is higher, obviously, it will just reduce the amount of cash that we're using from the Tunisia proceeds. So I do not see increasing any activity at this point in time.

Great. Thanks.

We'll now move onto Dan Morrison with Global Hunter.

Thanks. Most of my questions have been asked, but a couple -- if I missed it, I apologize. What are your current lateral links you're drilling in the Eagle Ford?

Typically 4500 to 5000 feet, Dan.

You haven't to 6000 like some guys are doing yet?

We have, but on a selected number of wells. Typical well is about 5000.

Great. And then in the weather-related -- weather impact on the quarter, have you got any kind of ballpark, or at the least timing, some kind of parameter that gives you a rough cut of what that means? How big that hit may be?

Yes, I think everybody watched the Super Bowl this past weekend. As you can see, Dallas was a mess, so that's obviously going to impact production in North Texas. Also the front will impact obviously West Texas and Mid-Continent, and we have not got a handle on it yet. At some point in time we have a better handle, we'll put out obviously some new numbers at some point in time.

Dan, as you know we have another front coming through with ice and snow tomorrow, so we're not out of the woods yet from the standpoint of impact to production, that's why it is hard to predict.

That's my next question. What is the temperature when things start to cause you problems?

Well, your typical issues are going to be in gas fields, freeze-ups, and that typically is not going to happen until you get pretty low. But realizing a lot of our gas is in Colorado, Kansas, and so on, there's a substantial impact due to freeze-ups in those areas. And it is not unusual there to get down to zero to five degrees above or 10 below, so those are substantial impacts. Permian Basin, we saw extremely low temperatures this last week, to the point where not only did we have issues pertaining to leaks in our water systems, but also just ability to move vehicles around. You get to a point where diesel fuels becomes more like a gel when you get to the temperatures we had last week, and so your drilling slows down, your movement of vehicles slows down and you have a lot of operational details to sort out and problems that are exacerbated by the ice and cold temperatures.

So we're just not at a point yet, because it is only a few days ago, to be able to predict exactly what the number is, but it is certainly the case that we're going to get affected by all that. Notwithstanding the fact we've had electrical outages that come as a result, as well.

All right. Great. Thanks.

We'll now move onto Richard Tullis with Capital One Southcoast.

Thank you. Good morning. Just to clarify on the costs for the 20-acre wells into the Wolfcamp, are those also $1.4 million, $1.5 million?

Yes, that's correct.

Okay. I know you mentioned a little earlier no asset sales planned near-term. Given the initial success with the 20-acre-spaced wells and just how well things are going in Spraberry, I mean, what are the current thoughts about maybe JVing some of your acreage there as a way to monetize some of that value?

Yes. We have talked about it. Obviously we need to understand the impact of the horizontal wells, the two into the Wolfcamp, the one that we mentioned in the Spraberry, before we even considered going out at all with a JV.

Obviously there has been a lot of people that contacted us positively about it. We don't need to do it obviously, but obviously what's got us excited is that there has been several outsiders paying $15,000- to $20,000- an-acre-plus coming into the Spraberry right next to our acreage. But we need to understand the horizontal opportunities before we even consider going out. So it could be several months before we make that decision.

Okay. Thank you. Just finally from me, it looks like you had a nice uptick in NGL pricing quarter-over-quarter. What's the outlook going out to 2011 and even beyond?

We still see it staying around bouncing between 45% and 55% of WTI, and 50% is a good number. Somewhere give or take 10% around 50%, so --

Okay. All right.

The industry can absorb this extra -- easily can absorb this extra ethane, petrochemical obviously making a lot of money for the first time in several years, I think a lot of expansion opportunities.

Well, that's good. That's all I had. Thank you.

Gentlemen, there are no further questions. Mr. Sheffield, did you have any final or closing remarks?

Yes, thank you. Again, we would like to thank everyone. Look forward to seeing everybody out on the road over the next few months and also for the next quarter. We'll talk to everybody later. Feel free to call Frank and our IR group on any further questions. Thank you.

That does conclude our conference for today. We thank you for your participation. You may now disconnect.