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Pioneer Natural Resources (NYSE:PXD)

Q4 2010 Earnings Call

February 08, 2011 10:00 am ET

Executives

Scott Sheffield - Chairman and Chief Executive Officer

Richard Dealy - Chief Financial Officer and Executive Vice President

Timothy Dove - President and Chief Operating Officer

Frank Hopkins - Vice President of Investor Relations

Analysts

Daniel Morrison - Global Hunter Securities, LLC

Brian Singer - Goldman Sachs Group Inc.

Leo Mariani - RBC Capital Markets, LLC

Brian Corales - Howard Weil Incorporated

Gil Yang - BofA Merrill Lynch

Richard Tullis - Capital One Southcoast, Inc.

John Nelson - Macquarie Research

Scott Wilmoth - Simmons

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Operator

Welcome to Pioneer Natural Resources Fourth Quarter Conference Call. [Operator Instructions] 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. 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 and 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 Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Frank Hopkins

Good day, everyone, and thank you for joining us. I'm going to briefly review the agenda for today's call. Scott's going to be up first. He'll review the financial and operating highlights for the fourth quarter of 2010, another solid quarter for Pioneer. He'll 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'll provide earnings guidance for the first quarter. And after that, we'll open up the call for your questions. With that, I'll turn the call over to Scott.

Scott Sheffield

Thanks, Frank. Good morning. I 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 #3, we had adjusted income of $59 million or $0.51 per diluted share. It excludes a net gain from unusual items about $106 million after-tax, or $0.87 per share. It also excludes unrealized mark-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 time frame, we achieved a growth target of 11%. Spraberry production, obviously, is way exceeding forecast with the new zones being open. 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, Eagle Ford Shale had 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 space in a period of nine months. We essentially hit 100 million a day equivalent in a nine-month startup 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, expected to be at 12 rigs by midyear. We've got three central gathering plants online, two more on by March and three more by year-end in 2011.

In addition, we continue 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 had delivered last week, in regard to our press release on finding cost and reserve replacement, we delivered 363% reserve replacement at approved 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 cost, 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, will be significantly down again by the end of first quarter based on that sale. We announced the sale of Tunisia's subsidiaries for $866 million. Everything's on track for a closing by the end of first quarter. Proceeds, obviously, we'll talk about that, will be redeployed to core U.S. assets, primarily in Texas.

Slide #4. 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 the activity in the Eagle Ford, 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 11 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%, 11% production growth rate, reflecting Tunisia as discontinued ops on the left side. And in addition for 2011, the 15% and 19% correlates to 125,000 to 130,000 barrels a day equivalent. And 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've had some weather downtime over the last week, which is not reflected in those numbers.

And again, over that three-year period, we're looking at 18%-plus, driven primarily by the Spraberry ramp-up and Eagle Ford ramp-up.

Slide #5. Obviously, very strong 2010 reserve additions. We ended the year a little bit over 1 billion barrels. As I've 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. The data have positive revisions, primarily from oil and the Spraberry. We did have some revisions in Raton, primarily to the improved differentials, not as much gas price, but 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, our -- all Spraberry, Raton and Eagle Ford PUDs are within one offset of PDP location. Table off to the right, obviously, Spraberry had the big increase, and you can see the lineup. 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 #6, a strong 2010 F&D performance. Again we had F&D costs of $9.96, excluding price revisions, below our targeted F&D cost of $10 to $15, also all in of $7.30, including price revisions. Reserve mix stayed fairly constant compared to last year, 97% U.S., 56% liquids. Proved developed and PUD ratio stayed very close to what happened last year. Proved reserves production, 22 years. Proved developed reserves to production ratio, 13 years.

Going into our capital budget for 2011 on Slide #7. 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. Eagle Ford will still be about $110 million. Obviously, this is net of the carry. Eagle Ford, obviously, is 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. And 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 '11, primarily for frac equipment and pulling 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 #8 shows the operating cash flow growth. We're increasing that. Also, up to a 25% CAGR growth rate with a result of our 18%-plus production growth rate CAGR during that same timeframe. We're going up from about $1 billion in 2010, up to $2.3 billion in 2013, about 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.

And finally, on Slide #9, 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're 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 the 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. Though we've added some there, but great hedging positions for years 2011, 2012, some in '13 and '14. 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.

Timothy Dove

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've got a couple of slides to talk about that. The result, really, of the fact we've been deepening the wells in our 2010 campaign in 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 this production for 2010. Remember, these are [indiscernible] wells all starting on the same point to determine the effect of the incremental deepening and interbedded intervals. And you can see on the graph clearly, we've got excellent empirical data that shows that we've had, approximately, a 30% increase in cumulative production for those wells during the first part of 2010. And 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 graph 11 or Slide 11, the new Spraberry 40-acre type curve, that’s 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've mentioned, and completing other zones in the interbedded shale/silts. With that said, it's also important to note that this graph does not include any contribution from Strawn, where we've been completing quite a number of wells in 2010, or the deeper Witoka that's under study as we speak. And it's also important to note that we have not yet incremented our resource potential numbers for this new type curve, which we'll 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's in sufficient state to be able to do so. And 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 some time during March. We will 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 waterflood 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 it 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'd say it's still early, but all signs are positive on the waterflood. 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 waterfloods in future campaigns.

On Slide 13. In the 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 and 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 that Scott has alluded to. We're also 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, and 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's 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 own services and third-party services, we anticipate the cost of the wells will be about $1.4 million to $1.5 million. It's really a combination of deepening the wells and creep we've seen over the last 12 months. That said, because of the deepening of the wells and the increase of the type curve, we still see very strong economics on these wells, something like 45% IRRs before tax.

And 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's 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 midyear, 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. We're very pleased to how that's going. Scott has already mentioned the fact we have seven rigs running, as we speak, going to 12. Importantly, we've done a great job so far of reducing drilling time and improving completion techniques. You look at the current number of days drilling and any other measures similar to that, such as cost per foot, we're exceeding what we first began in the play by some 20% to 30% on all 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 completions 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 drilled 41 wells. We have 21 on production, and three wells waiting on hookup. 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's 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 will now be in place on schedule both, one in the second quarter and one in the fourth quarter. And importantly, as we drill up and down the play, preserving our leasehold, we're seeing really predictive well performance continuing, which is a very important factor. 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 exited forecast rate. That forecasted exit rate at 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's going exceedingly well. And we're looking forward to continue ramping 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 be 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 were 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 flow back to these wells. They’re generally drill with 3,500-foot laterals, and we're able to keep the cost under control of 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 fracing 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 of 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're going to be drilling and fracing 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 a potential larger development in the Moraine-Torok area south of the Igorac [ph] (0:33:43) Island. So these wells are important to watch in terms of the future potential for a project on the North Slope.

I'd 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's 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'm going to stop there and pass it over to Rich for a discussion of fourth quarter financials and his outlook for the first quarter.

Richard Dealy

Thanks, Tim, and good morning. Turning to Slide 18, fourth quarter earnings. Net income attributable to common stockholders was $80 million, or $0.67 cents 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'm not going to go in detail here. We did put a further 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, but wouldn’t 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.

We turn to Slide 20 and look at price realizations. The bars show what our realized prices were before hedging and VPP 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 continue 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 is 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, where we thought we were going to end up owing. In the fourth quarter, we got the actual bills in, and we're a little over accrued. So that was a positive effect of $0.43 per BOE in the fourth quarter.

Turning to Slide 22 and the first quarter guidance. As Scott and Tim both mentioned, this guidance doesn't reflect the weather we had last week in it. 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 cost of $11.75 to $13.75, very similar to where we've been in past quarters. If you go down the list, everything's very similar to where we've been in past quarters. The couple of things I will point out is on cash taxes. With the sale of Tunisia, that was a place that we're paying cash taxes. So the only place we're really 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 stop there, and we'll open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll now take our first question from Mitch Wurschmidt with KeyBanc.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Can you give a little more on the-- if you're going down to the Strawn or the Atoka deepening some of those verticals, what's the sort of incremental EUR you get and sort of the incremental well cost?

Timothy Dove

This is Tim, I'll answer that question for you. First of all, as we've 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 EUR is probably in the same range, 20,000 to 40,000 BOE.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And what's the extra cost, I guess, to pick that up?

Timothy Dove

Approximately $100,000.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

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

Timothy Dove

Well, I think we're trying to be conservative in everything we put out. So you can expect that in the future as well. But suffice it to say, there's 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 jump steps or jump shifts in production by this technology application.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And I just wondered -- I know you didn't give any -- on the Wolfcamp shale, it's still flowing back or the Wolfcamp carbon I guess is flowing back. But on the shale, can you talk a little bit about the attributes of it? Or lithology-wise, is that comparable maybe to some of the other plays and we’ve seen shale plays?

Timothy Dove

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

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And 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 kind of when you're looking at getting cash flow neutral again?

Scott Sheffield

Yes. The $200 million we're spending on the vertical integration will go down significantly going into next year. Land activity on other, will obviously go down going to '12. So obviously, the overspending using the Tunisia cash this year will significantly go down going into '12 and '13.

Operator

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

Scott Wilmoth - Simmons

Just looking at your 2011 CapEx budget, what assumptions you guys currently making for well cost? Are you guys assuming current well cost or some continued inflation throughout the year.

Timothy Dove

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

Scott Wilmoth - Simmons

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

Timothy Dove

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.

Scott Wilmoth - Simmons

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

Timothy Dove

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 cost and so on. Where we did see a significant increase was in pumping services, just as it's 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 cost 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're seeing about a 20% bump in rig costs for 2011 that is associated with most of our rigs. And so accordingly, it's a combination of those that have landed us at the new run rate.

Scott Wilmoth - Simmons

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

Timothy Dove

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

Scott Wilmoth - Simmons

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

Timothy Dove

It's about a 4,000-foot lateral, 14 stages. A traditional Permian type completion from the standpoint of horizontal drilling in this case so that's a plug and perf.

Operator

And our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

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

Timothy Dove

First of all, on Reliance. I anticipate that, that carry probably is done early part 2013, late 2012. And so I think that's going exceptionally well. In the Eagle Ford, what's your first question again? I got them mixed up.

Brian Singer - Goldman Sachs Group Inc.

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

Timothy Dove

Well, let me give you a little bit of recap of what I said earlier, which is on the drilling time and the cost related to drilling, we're seeing very dramatic improvements in efficiencies. And this is measured and however you want to measure it. Cost per foot, dollars on each well, days, and we're seeing reductions in the neighborhood of 20% to 30% or more since the Eagle Ford campaign began. And that's simply 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's a dramatic increase in the completion cost 100%. And as a result, we're seeing the total well cost being similar to where they were in 2010. The drilling component of which is substantially down, the frac component of which is up.

Brian Singer - Goldman Sachs Group Inc.

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

Timothy Dove

Today, we're probably at 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 that latter part of the third quarter. 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 are on these wells. And I think when all this is factored in, and when we start getting the proper number of frac fleets out there both Pioneer and third party, then 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.

Brian Singer - Goldman Sachs Group Inc.

Lastly, just looking at 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 increase in all 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?

Scott Sheffield

Yes, Brian. Our cash cows in Mid-continent and Raton have had very little decline, and they will continue to be cash cows. A little bit of the budget will go into -- the other category on my slide would go into Raton. And a little bit into Mid-Continent, maintenance capital, to reduce the 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 have a lot of upside we need to evaluate over the next couple of years. So right now, we see no other assets for divestiture.

Operator

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

Brian Corales - Howard Weil Incorporated

A couple of questions on the Eagle Ford. Once you get the company-owned frac fleet, what would that AFE look like?

Timothy Dove

Well, I think it's the case that our current completion cost in Eagle Ford of about $5.5 million. We think it's very possible that we could be able to frac these wells ourselves for $1.5 million to $2 million less than that. Of course, on top of that you have the drilling cost. So a $7 million to $8 million current AFE could be dropped in the neighborhood of $1.5 million to $2 million.

Brian Corales - Howard Weil Incorporated

And then also, you talked about the efficiencies in 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 five to six BEs. Is that kind of trending higher than that or where does that sit today?

Timothy Dove

I think we feel that's been very consistent up and down the trend and of course, we have a substantial amount of 3-D seismic. As you know, we've 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 into the gas window. So I think we can very clearly, and in fact we've done it exceptionally well, predict what well performance is going to do. And the well has been very consistent with those predictions, which is a very positive thing because you've got a substantial amount of aerial extent in this play. If you feel like you have a predictable outcome through the acreage, that's a very big positive.

Brian Corales - Howard Weil Incorporated

Do you all have the future development cost for your reserves?

Richard Dealy

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

Operator

And our next question comes from Leo Mariani with RBC.

Leo Mariani - RBC Capital Markets, LLC

You guys talked about sort of a blended well cost to the Spraberry of $1.4 million to $1.5 million? Just to clarify, could you give us what you think the number is with PXD equipment versus third party?

Timothy Dove

It’s about –- we’d say it's about $1.3 million or so for PXD 100% well, and it's probably $1.8 million door-to-door all third-party equipment.

Leo Mariani - RBC Capital Markets, LLC

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 probably [ph] (0:51:09) roughly 30% to 40% of your acreage. I just wanted to see if that number's accurate. And then I also just wanted to check in to see how much of your acreage you thought the Atoka was present on?

Timothy Dove

Strawn, we still believe is in that neighborhood. I think it's 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 are some data that suggest that it could be at least potentially perspective for upwards of 25% of our acreage. Of course, it's going to involve deepening of wells. So we will be doing a number of tests, at least a few tests during 2011 to get that answer for you.

Leo Mariani - RBC Capital Markets, LLC

In terms of your Spraberry here, you guys talked about a 30% increase in EURs here adding some additional zones. What did the third-party engineers give you guys in your year-end '10 reserve report? Did they give you that much of the increase as well on some of your wells here?

Timothy Dove

Well, I think quite a large number of our wells are just producing wells and 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.

Leo Mariani - RBC Capital Markets, LLC

So I guess that’s tough. Hopefully, it will show up in your reserve report during the course of the year as the third party gets more comfortable, that'll be reasonable.

Timothy Dove

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

Leo Mariani - RBC Capital Markets, LLC

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

Scott Sheffield

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's probably very positive for OMV.

Operator

And we'll now take our next question from Gil Yang from Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

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

Scott Sheffield

Based on these two wells, obviously we anticipate to probably drill some more. Where also the team is looking at drilling probably our best zone, we call the Jo Mill zone in the Spraberry. They're picking out a candidate now. So we'll put one in the Spraberry. If you recall, we've talked about doing some horizontals about 15 years ago. And in the Jo Mill 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 [ph] (0:54:24) because there's not enough horsepower out there. These wells, the type of frac job they need and there's not the type of rigs that drill horizontals. So a lot of our rigs can be modified if needed. We'll probably have to order more frac equipment if it happens. But I see that taking probably a good couple of years before we make that decision. So we're going to drill probably a few more later this year, a few more going into '12 to test both the carbonate and the lower shale zone. And then as I said, we'll put one in the Jo Mill Spraberry.

Timothy Dove

One note is that 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.

Gil Yang - BofA Merrill Lynch

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

Timothy Dove

Correct.

Gil Yang - BofA Merrill Lynch

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

Scott Sheffield

No. We still have over 9,000 locations on 40s. So basically, we're finding out that there's 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. We don't see any issues there.

Gil Yang - BofA Merrill Lynch

What have you done with the 20-acre down spacing, and what were 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?

Timothy Dove

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, we're seeing from these 20-acre wells is clearly production above the 110,000 BOE type curves. We're trying to assess exactly how far it is whether it equals the 140,000 or slightly below the 140,000 so it's 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’ll have a continuing increasing data set as we go forward.

Gil Yang - BofA Merrill Lynch

So it could be as high as 140,000 -- so it’s possible you're seeing no interference.

Timothy Dove

Well, I anticipate the interference would not be seen for some time. We have such low-permeability rock here that the case of the 20-acre wells 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 that it is significantly over the 110,000 BOE type curve.

Gil Yang - BofA Merrill Lynch

Just in terms of 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 gas strip, is that fair to say?

Richard Dealy

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

Gil Yang - BofA Merrill Lynch

And so that'll start this year?

Richard Dealy

Yes.

Operator

And we'll now take our next question from John Nelson with Macquarie.

John Nelson - Macquarie Research

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?

Timothy Dove

Well, the only thing that's different about these 20 acres as compared to some of the prior campaigns is that they are also being deepened 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.

John Nelson - Macquarie Research

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

Timothy Dove

Well, 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's actually improving. But the completion techniques are really oriented towards trying to determine whether or not if we need, for instance, 14 or 15 frac stages or whether we can get by with 12, it's simply a matter of cost. And the way we're determining that of course is through microseismic techniques. And so really, it's 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.

John Nelson - Macquarie Research

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

Richard Dealy

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

Operator

And we'll now move on to Dan Morrison with Global Hunter.

Daniel Morrison - Global Hunter Securities, LLC

What are kind of your current lateral lengths you're drilling in the Eagle Ford?

Timothy Dove

Typically 4,500 to 5,000 feet, Dan.

Daniel Morrison - Global Hunter Securities, LLC

You haven't gone to six like some guys are doing, yet?

Timothy Dove

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

Daniel Morrison - Global Hunter Securities, LLC

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

Richard Dealy

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. We have not got a handle on it yet. So at some point in time, we have a better handle, we'll put out obviously some new numbers at some point in time.

Scott Sheffield

And Dan, as you know, we've got our 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's hard to predict.

Daniel Morrison - Global Hunter Securities, LLC

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

Timothy Dove

Well your typical issues are going to be in gas fields freeze ups and that's typically not going to happen until you get pretty low. But realizing a lot of our gas is in Colorado, Kansas, so on, there's a substantial impact due to freeze ups in those areas. And it's not unusual there to down 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 icy cold temperature. So we're just not at a point yet, because it's only a few days ago, to be able to predict exactly what the number is but it's 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.

Operator

And we'll now move on to Richard Tullis with Capital One Southcoast.

Richard Tullis - Capital One Southcoast, Inc.

Just to clarify on the cost for the 20-acre wells into the Wolfcamp, are those also $1.4 million, $1.5 million?

Timothy Dove

Yes, that's correct.

Richard Tullis - Capital One Southcoast, Inc.

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 at Spraberry, what are the current thoughts about maybe JV and some of your acreage there as a way to monetize some of that value?

Scott Sheffield

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 consider going out at all with a JV. Obviously, there's been a lot of people that have contacted us positively about it. We don't need to do it obviously. But obviously, what's got us excited is that there's 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.

Richard Tullis - Capital One Southcoast, Inc.

And just finally for 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?

Richard Dealy

Yes, we still see it staying around, bouncing between 45% and 55% of WTI and 50% is a good number, take 10% around 50%. The industry easily can store this extra ethane. Petrochemical industry is obviously making a lot of money for the first time in several years. I think a lot of expansion opportunities and so.

Operator

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

Scott Sheffield

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

Operator

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

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