先鋒自然資源 (PXD) 2009 Q4 法說會逐字稿

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

Pioneer has prepared PowerPoint slides to supplement 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 and future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release, on page two 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.

Good day, everyone, and thank you for joining us this morning.

Let me briefly review the agenda for today's call. Scott is going to be the first speaker. He'll review the financial and operating highlights for the fourth quarter and for the full year of 2009. He's then going to give you some thoughts and comments on the Company's plans for 2010, and a couple years beyond that. After that, Tim is going to update you on our drilling plans, with particular focus on the Spraberry and Eagle Ford Shale. He'll also touch on what's going on in Alaska and Tunisia this year. Rich will cover the fourth quarter financials in more detail, and provide earnings guidance for the first quarter of 2010. After that, as usual, we'll open up the call for your questions.

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

Thanks, Frank. Good morning. Appreciate the time and effort everyone has taken to listen to our quarterly call.

We'll start on slide number three on highlights. For the fourth quarter of 2009, we had adjusted income of about $95 million or $0.80 per share. From a clean standpoint, after unusual items we had a number of about $0.18 per share versus the consensus of about $0.05.

We had very -- one important unusual item. Through recent rulings of the 5th Circuit and also the Supreme Court, we're able to book a royalty refund of $119 million. We expect proceeds from that during the first half of 2010. In addition, we do expect to receive additional interest on top of that of about $25 million to $30 million, which will book at a later date. We'll using existing net operating losses to shelter any taxes to be paid on those proceeds.

From the standpoint of production, we had fourth quarter 2009 production of 106,000 barrels a day. That reflects more production curtailment of about 2,500 barrels a day, due to longer than anticipated maintenance, and shutdown of our detail facility in South Africa that processes our gas to liquids. We did receive -- we're back to full production, and resumed in early January for this project. We produced 115,000 barrels of oil equivalent per day in 2009. We're up 5% on a per share basis versus 2008, 3% absolute, despite a very curtailed drilling program of going from 30 rigs to one rig during the year.

From a reserve standpoint, we added proved reserves of 52 million BOEs equivalent, or 114% of full-year production for drilling success and performance improvements. Drill bit finding costs of $7.42 per BOE, excluding price revisions, and an all-in finding cost of a little over $9 excluding price revisions. During the year we reduced debt by up a little over $200 million, a combination of the sell of the Gulf of Mexico shale properties, our draw down into the [MLP PSE], and showing free cash flow during the year. In addition, during the quarter we did issue $450 million of 7.5% senior notes to reduce our credit facility indebtedness. As we have been talking about, we have significantly ramped up Spraberry drilling activity, which Tim will talk more about.

And then, lastly, we have drilled and tested the highest rate Eagle Ford Shale well to date, an IP of 17 million a day. And with our JV process starting in the next two weeks, obviously we're very optimistic about that process, expect to close it sometime later in the second quarter. With the -- we do have a resource potential of about 11 TCF equivalent from a gross standpoint, on roughly about 65% of our acreage. We expect to drill up to 1,750 locations on that, and we'll be ramping up to 14 rigs over the next three years in the Eagle Ford play, which will significantly put it in the camp very similar to the Spraberry Trend area, which will both drive the growth to double-digit production growth starting in 2011.

Turning to slide number four, returning to quarterly production growth in the first quarter of 2010, again, as you can see we're already ramping up the first quarter of 2010 with our estimate of 112,000 to 117,000 barrels a day equivalent. We'll ramp up quarterly, and expect to exceed 10%-plus from fourth quarter 2009 to fourth quarter 2010, and then resuming to double-digit production growth in 2011 and beyond, especially with a number of locations we have in the Spraberry Trend area field, and also in the Eagle Ford Shale play.

Slide number five, 2009 reserves, as we've already press released, we reported year end reserves of 899 MMBOE. As I mentioned earlier we added 52 MMBOE of primarily successful drilling in the first part of the year, and also improved performance. We did have negative price revisions of 65 million BOEs, primarily due to our gas assets, primarily due to PUDs in Raton, which we had to run at about a $3 gas price flat, for the next several years. Obviously, at $5 we'll recover most of that back, and we'll talk about what happens at $6 flat. We were offset by positive oil and natural gas revisions of 14 MMBOE. That was running at a price a little bit over $60. As I mentioned, we recovered 98% of our Raton revisions at $5 flat non-mixed gas price. We would add 81 MMBOE of gas reserves at $6, which is more reflective of the strip gas price, more than a 100% of 2009 negative gas provisions. And 18 MMBOE of liquids at $80 flat. As you can see in the table, we had a PV 10 of $9.3 billion before tax at $80 and $6 flat.

Obviously, a controversial item in regard to how PUDs are scheduled. Obviously with our significant ramp-up in cash flow, and our significant ramp-up to 40 rigs over the next several years, it's obviously fairly easy for us to drill all of PUDs within a five-year time frame. So we have decided obviously to go within the five-year, which is a guideline right now within the SEC.

All Spraberry PUDs are also within one offset PDP location. Obviously, we noticed that several people are booking two and three off-set locations away. We have decided at this point in time not to do that. Looking at the table, you can see that obviously the Spraberry is still half the Company. It pretty much stays around 500 million barrel if you look at both cases, whether it's in that [$62 and $3.80, or $80 and $6]. Raton, we see a big pick-up obviously at $6 gas. The rest of the assets stayed fairly close to the same. But we would get up close to a billion barrels of proved reserves at $80 and $6 flat.

Turning to slide number six, a very strong F&D performance. Again, all-in finding costs, a little bit over $9, excluding price revisions, and a drill-bit finding cost of a little bit over $7 excluding price revisions; a significant improvement versus 2008. Reserve mix obviously is staying -- we are predominantly liquids, 98% in the US, 54% liquids. Obviously with our mix of 70 -- most of our focus on liquid drilling over the next several years, that 54% should continue to increase significantly over the next several years. Also with the continued focus on drilling of PUDs, we hopefully over the next five years should see the proved developed percentage obviously continue to go up. Our ratios, proved reserve to production is 20 years, with our proved developed reserves to production of 12 years, still one of the highest in the industry.

Turning to slide seven and eight, talking about cash flow and CapEx, 2010, obviously our cash flow has been fluctuating between $1 billion and $1.1 billion with the recent strip. Obviously, the strip came down over the last two or three weeks, but over the last three or four days it's been coming back up, obviously a little over $1 billion. But we are still expecting around $1 billion of cash flow for 2010. We've been spending somewhere between $800 million to $900 million of CapEx, with 90% of it oil-focused. We'll talk a little bit more about the ramp-up in Spraberry, and also our other areas, with Tim in a second.

In addition, with our three-ways, obviously we have upside up to about $1.3 billion if we see any type of increase in prices. Also in addition, with receiving the MMS refund sometime during the first half, both the proceeds of $119 million in interest, potentially getting it up to $150 million, we'll use the proceeds to help support and ramp-up -- the Spraberry and Eagle Ford ramp-up.

Turning to slide number eight, in 2011, again, the cash flow significantly picking up from about $1 billion cash flow to about $1.3 billion. With our three-ways at $99 upside and $8.70 gas, it allows us to collect potentially up to $1.8 billion. Obviously, most of the excess cash flow, the $300 million, will be going into the Spraberry Trend area field, and then ramping up over 700 wells during 2011.

Finally, on the last slide, before we turn it over to Tim, slide number nine, "Why Invest in PXD?", obviously we have one of the largest inventories, with over 20,000 [scrubber] locations, potentially up to 1,750 locations in Eagle Ford and other locations throughout our asset base. The focus is over 75% liquids. So we're -- obviously at a point where oil is trading 15-to-1 to 16-to-1 to natural gas, it's nice to be able to have such a liquid-rich inventory. Obviously the focus is ramping up activity. Tim will be talking about some of the efforts we're doing in regard to purchasing rigs and new materials, and locking in prices for the next two years.

The Eagle Ford joint venture, obviously we're very excited about our last two wells we've drilled. This JV process, a lot of excitement here. Also the excitement about it from the outside in regard to this play, obviously we're expecting to announce something hopefully by the end of the second quarter.

Also we have attractive derivative positions through 2012. We've done more hedging in 2011 and 2012, with the recent run-up about three or four weeks ago in regard to the commodities, which givers us upside of $99 in 2011, with downside protection, and also up to $120 in 2012, with $8.70 gas in both of those years.

We'll continue to deliver free cash flow. We have a strong financial flexibility. Again, strong margins with the 54% focus on liquids and most of our drilling focused on liquids. Obviously, again, we're blessed with a very low decline asset that delivers very stable cash flow.

Let me now turn it over to Tim.

Thanks, Scott.

In the interest of brevity, as Frank had already mentioned, I'll limit my discussions primarily to an update on our activities in the Spraberry Trend and also the Eagle Ford Shale. Toward that end, on slide 10, what we can say definitively is our Spraberry ramp-up is well underway and is very much on schedule. Our fourth quarter 2009 production was about 31,000 BOE per day in the field; a pretty strong quarter, considering that was the quarter where we we're starting up drilling, we're starting up a significant work-over program to take advantage of relatively high commodity prices, and it's the starting point for a significant growth trajectory that we'll talk about on the next slide.

We only drilled 48 wells last year, that's maybe an all-time low for Pioneer; but that said, we're embarking on a significant ramp-up, and in fact plan to drill about 425 wells this year. We're on schedule, from a rig standpoint; we'll have 14 rig running here shortly in February, and on schedule to have the 19 rigs in place by midyear and 24 at year end, heading towards a 700-well campaign in 2011. Importantly, most of these wells will be deepened into the Wolfcamp and/or will have completions in the shale/silt intervals that we've proven can contribute to productivity and EUR increases in these wells.

The returns are still magnificent really, 50%-plus IRRs before tax. The costs of return to essentially an equivalent level to where they were in 2006, and that's about a 30% reduction from where they hit their peaks in the last couple of years. We really believe very confidently that we can begin to grow production again, and grow it somewhere in the neighborhood of 10% this year, and increasing that in early years as we ramp up drilling. We have begun the 7,000 acre waterflood project with several rigs, in fact three rigs, running in the area. We expect to complete the activities related to the installation of the waterflood in the second quarter, and we'll be looking for production impacts for that project somewhere in the neighborhood of the year end 2010 or early 2011.

Slide 11, as I alluded to, shows a compilation of what we can expect when it comes to Spraberry growth out of the ramped-up campaign. We resumed drilling, as I mentioned, in the fourth quarter. You can see, as we begin the manufacturing process of oil development in the field, we can grow up to about a 20% figure by the implementation of the rig schedule shown at the bottom, some 425 wells being drilled this year, 700 at 2011, and getting up to 40 rigs, which would drill 1,000 wells in 2012. It's clear that we can increase potentially above 40 rigs, but that's just a large target, 1,000 wells. We think that's easily doable in 2012.

We have a long track record of growth in this field. We know what the wells produce. We operate over 6,000 wells. So we can say with a great deal of confidence that this production growth from the Spraberry Trend is achievable and doable, and is extremely predictable.

Turning to slide 12, Scott has alluded to the fact that we've taken a lot of different steps, which are really important when you consider this is more of a manufacturing process, and really in the context of all resource plays, it's very critical to be protective of margins, and a lot of the steps we're taking are taking are an effort to mitigate potential cost creep, and to further vertically integrate our operations, and to provide some of our own Company-operated services in the Spraberry as our drilling ramps up. We really have yet to see any significant cost creep in the Permian Basin, but the idea here is to foreshadow any potential further increases in costs with mitigants by Company-owned facilities and equipment.

Toward that end, we have announced that we will be purchasing approximately 10 rigs, which if you think of in the context of a 40 well program in 2012, would cover some 25% of our drilling program. We've announced through time our inventory of pulling units now at about 18, at any given time in the field we have about 30 pulling units working, and those have given us significant cost savings, especially in the peak market rates we saw in 2008, some 40% less than market is the cost at which we can operate those facilities. And that is -- those acquisitions of pulling units have essentially already paid out.

We have transferred a frac fleet down from Raton to work in the Permian Basin. Each of these can frac fleets can frac some 225 wells per year. Toward that end, we've made the decision to acquire a second frac fleet, which will be arriving in early 2011 for the 2011 campaign. The engineering design is underway, as we speak, for that frac fleet. So suffice it to say, we'll become very self-sufficient when it comes to in the neighborhood of 450 to 500 fracs per year, and perhaps increasing above that as we look towards 2012.

Other ancillary services are listed on slide 12, but suffice it to say that these are all intended to further vertically integrate our operations and prevent cost creeps that we have seen in the past. Importantly, one thing we've done that is critical to success in terms of margin preservation is to put in place some longer-term contracts for supply of goods and services. For instance, we have contracted our tubulars for all of our drilling program out in the Permian Basin through 2011. We have also acquired pumping units that will suffice for our program through 2011. And to the extent that we're fracking our own wells, as I mentioned, with our own frac fleets, we have also contracted the necessary sand supplies through 2012.

So, in essence, this gives us a great deal of confidence. We've taken significant strides in protecting margins and controlling our own destiny when it comes to our operations, and it gives me a great deal of confidence in our ability to ramp up the drilling and meet the plans for this important field in Pioneer.

Now turning to the next slide, slide 13, talking about Eagle Ford. Scott has discussed the Eagle Ford in some detail, when it comes to the joint venture, but suffice it to say today we have two rigs running in the field. Today those wells are being drilled in DeWitt and Karnes County, where we're really focusing on our liquids-rich acreage. A substantial amount of our acreage is actually in the liquid-rich band shown here in the intermediate sections, sort of the olive color in the central part of the basin. The joint venture activities are proceeding well, as Scott mentioned, and the result of which would be hopefully a significant ramp-up in drilling in the second half of 2010, with a JV partner.

The two wells we've drilled so far in the field that were successes, the Sinor #5 and Crawley #1, have given us a lot of confidence in terms of kind of rates the wells can make, particularly the Crawley #1 well, having been drilled toward what we would consider more of the dry gas window, produced at the highest rate we've seen in the field for gas well, some 17 million cubic feet a day IP. That gives us a lot of confidence that, even if we're drilling wells in the dry gas window, we feel like we can do so at rates that will be highly economic.

By virtue of our 3D and other data in the field, of course we've accumulated a huge amount of data related to our Edwards drilling campaign over the years. We are the league leader when it comes to the most data in the Trend, and we're the technology leader when it comes to the application of all of the data that we have acquired over the years. So we continue to be very excited about what we're seeing in the Eagle Ford Shale. I think that, needless to say, it's an important project for the Company, and we have a great team of people now working on the Eagle Ford Shale, and look forward to these joint venture deliberations.

So that concludes my slides. Of course, in Pioneer we have many other assets contributing the our operational successes, and they are captured in supplemental slides which are attached at the end. But let me make a couple of comments about a couple of our areas. Alaska, for instance, we, as you know, have a continuous drilling program going in Alaska with one rig running. It will be the subject of drilling several wells in 2010, including two Kuparuk C slotted wells for the Winter, and then five Nuiqsut wells for the summer, as well as testing in this zone here shortly that has yet to be tested. Suffice it to say, Alaska, by virtue of the results from these wells, will be an important component of our growth in 2010.

In Tunisia, we have a three-well operated package that will be commencing probably it looks like now in March, and we'll have also approximately three non-operated wells drilled there as well. Of course, we're getting important contributions from many of our other operating areas, including the Barnett Shale, our Mid-Continent fields, Raton, in terms of important baseline production and cash flow as well.

With that, I'll pass it over to Rich for our discussion of the fourth quarter financials and our outlook for this year.

Thanks, Tim.

Turning to slide 14, net income attributable to common stockholders was $57 million for the quarter or $0.48. That did include a mark-to-market loss, non-cash, of $60 million before tax or $38 million after tax, so an additional $0.32, to got to our adjusted income of $95 million or $0.80 as Scott discussed. It does include a number of unusual items that are detailed on the slide here, that total up to $0.62. The largest item, as Scott talked about, was the MMS refund that is included in discontinued ops, given the fact that the deepwater properties were sold and included in discontinued ops in previous years.

Looking at the bottom of the slide, and really looking at fourth quarter guidance relative to fourth quarter results, we've talked about production being at the lower end of guidance, really related to the extended downtime at the non-operated GTL plant in South Africa. Production costs, I'm going to talk about in a little more detail a couple of slides later. Expiration abandonments came in the lower part of the range, primarily just geoscience work and a little bit of acreage costs. DD&A, below the guidance; two items really causing that. One, the reserve adds that Scott talked about adding to our reserve base at year end, those came on in Q4, so that brought the rate down. In addition, South Africa production being down, it's one our lower operating cost assets, but one of our higher depletion assets, so not having that production caused our weighted average to be lower as well. G&A came in as expected. Interest expense was at the upper end of the range, primarily reflecting the issuance of the 7.5%, $450 million that we issued in November, so that incremental interest expense being in there. Then the rest of the items here all were within our range of expectations, so nothing unusual there.

Turning to slide 15, price realizations, in the quarter we did benefit from higher prices, as you can see from the bars, across the board. Oil was up 13% relative to the third quarter to $88.16. NGLs were also up 13% to $37.54 per barrel. And gas was up 25%, up to $4.56. So good improvement in terms of price realizations for the Company. At the bottom there's two bars there, one -- for your information, the first one shows what's the derivative impact that's included in price, really reflecting our -- before switching to mark-to-market accounting, the hedges that were in place at that point in time. The second row at the bottom shows the derivative impact to these prices, that is not included in price, to try and do just the income statement and our derivative activity line. So that's there for your information.

Turning to slide 16 on production costs. As we've talked about in prior quarters, the Company has, and the asset teams particularly have, done a tremendous job in reducing overall production costs. You can see relative to where we were in the fourth quarter of 2008 versus the fourth quarter of 2009, down about 22% or $3.25 per BOE. We talked about a lot of the items in past quarters, so I'll focus more of my comments on the third quarter comparison to the third quarter, and point out a couple of unusual items that hit in the fourth quarter. One, we did have higher workover expense per BOE in the fourth quarter; that's really an impact of higher oil prices, and we've increased our workover activity to restoring production on some repair items. And the production and Ad Valorem Tax line item, it is lower in the fourth quarter, reflecting tax refunds we did apply during the third quarter, fourth quarter, for some gas wells -- on gas wells that qualify for high-cost tax refunds, and we did get those, so those are in there. And then if you look at base LOE, the increase there is once again attributable mainly to South Africa, where the production there is low-cost operating cost, and so the weighted average, without that production, caused that average to be up slightly. We also had little bit of increased field maintenance that just hit in the fourth quarter.

Turning to slide 17, switching gears to talk about first quarter guidance, daily production guidance of 112,000 to 117,000 BOEs per day, very similar to -- exactly the same what we had been predicting or forecasting last couple of quarters. Production costs similar to last quarter, $11.50 to $13.50 per BOE, exploration and abandonment similar to what we've had in the past. DD&A does reflect the new rules. We're predicting it will be $14.50 to $16 per BOE, reflecting a rolling 12-month average under the new SEC rules for pricing purposes.

Other major items, interest expense $45 million to $48 million, up slightly from prior periods, once again reflecting the incremental interest associated with the bonds that we issued. We have swapped a big chunk of those bonds back to floating, that's running through our derivative activity as well.

Other expense, we've had a number of people who asked us to start giving some guidance on that, so we have added that in here at $12 million to $17 million, so that's a new line item that we have added. And the rest of the items, with the exception of non-controlling interest, are consistent. The non-controlling interest is up slightly from prior quarters, reflecting the equity offering that we did at Pioneer Southwest during the fourth quarter.

So with that, that concludes our comments. As Tim mentioned, there are a number of slides in the back in the supplemental information that I do encourage everybody to look at, to help with your modeling and activity on our other assets. So that's there for your information.

With that, we'll stop here and open up the call for questions.

Thank you.

(Operator Instructions)

And our first question today will come from Dave Kistler with Simmons & Company.

Well, thanks. Looking at the Spraberry and locking down the well costs there, could you guys walk us through little bit in terms of what kind of variability remains? So, I am just thinking of it from, if there were service costs increased there over the next year or two, how impactful is it, if you locked down at 50%, 60% of variable costs? Just trying to get a handle on that standpoint.

That's a good question. The rig rates are essentially fixed for this year. Okay, the and as the pumping services for this year, those rates were effectively fixed in one-year deals. As I mentioned earlier, we have the tubulars lined out for this year, next year. You are saying, pumping it. The only thing that really I would say is, materially at risk for creep, would be things like labor cost, electricity, electricity of course being subject to really what happens to natural gas price. And so I think, those are the two major factors but it is a high percentage of the low cost essentially locked in.

Okay. That's helpful. And just thinking of it from a term standpoint, it looks like you definitely nailed down for this year. And then, I think some of them you're reaching into 2011 and 2012. Can you just kind of give us a little bit more definition on, what percentage or what portion of it is open for creep in 2011 and 2012?

Well, first of all, we have locked in, as I mentioned the tubulars, sand and pumping unit costs for 2011, and the sands for 2012, so those components are locked in. What are not locked in other than the company own rigs are, but what was going to happen to rig rate for 2011. In addition to which other ancillary costs, such as I mentioned labor, electricity and this kind of thing, is subject to variation in 2011 as well. So it's a lesser percentage than what we're looking at 2010.

And, but that said, we're taking some of the big steps to make sure we and mitigate some of those cost increases by having our own equipment in place. So to the extent we're getting pressure from the standpoint of cost creep. We're pointing where we can do many of the same services for ourselves internally and hopefully that will keep a lid on future increases.

Great. That's helpful. And then kind of coming over I guess to the production side out of the Spraberry and obviously key revenue driver as you pursued the additional shale/silt zones. Can you give us any sense for what sort of per well production upticks or EUR you might be looking at associated with that?

Dave, what we can say is, more averaging statement on that, which is to say, if you look at some of our public information on this, our initial rates of production from our newer well campaigns have been approximately 17% higher than those of the same averages as per few years ago. So we know we're incrementally adding that at an average, realizing each well is different. But we've seen some areas where deepening wells at Wolfcamp can add some 35% incrementally.

We've seen some areas where shale/silt zones can add 20%. But what I can tell you definitively, empirically we can say that our wells on average have been 17% better in terms of total campaign in 2008, which is the relevant year where we had more wells drilled.

Okay. That's helpful. And then, I guess, you know that, somewhat reflected in Q4 2009 production even though there weren't a ton of wells drilled that out of the Spraberry, I believe was a little bit higher as I look toward and please correct if I'm wrong on that, as I look towards 4Q 2010 and kind of thinking about the guidance there, that guidance remains unchanged relative to this higher base that you're starting with. You know, not trying to suggest you guys are big conservative there, but is that a possibility? (Laughter)

Go ahead and suggest it, it's fine. I mean, I think, we feel like we're trying to be conservative. But let me just comment on the fourth quarter. We also -- Rich Dealy alluded to this, you can see these are some of the numbers. But we have been incrementally adding workovers in the fourth quarter in response to just increase activity, higher prices and that's yielded really significantly through the fourth quarter production. But looking out we established these curves that are shown on slide 11, where a focus are being conservative. So I'm not surprised with that conclusion.

Okay. I appreciate it, guys. I'll let somebody else hop on.

Next we'll hear from Michael Jacobs with Tudor, Pickering, Holt.

Thanks, good morning, everyone. Good job on the Spraberry actually offset there but had a couple of high level conceptual questions on the Eagle Ford. Clearly its early days in DeWitt County. As of last Friday, DeWitt County the rigs running in that area, you have got two of those. Can you give us any color on overall industry activity kind of what you're seeing, what you're hearing?

The last report, Michael, that I've seen is 29 to 30 rigs in the Eagle Ford running that we can add up, and so that's the current activity and it wouldn't surprise me if it gets on up to 50 rigs plus based on some the results that we're seeing.

Okay. And when we specifically look at DeWitt outside of Pioneer's rigs, it seems like there are six other rigs running from other large operators. Are there any anecdotes on typical completion design and perhaps production rate that you're seeing from your neighbors and any additional color on the typical completion would be interesting?

No. We do not at this point in time have any other information, we're not, I mean, DeWitt is just one County, it goes all the way down to McMullen. We have acreage all the way through. So we think from DeWitt all the way to McMullen is going to be very perspective. So what we don't know is having all the 3D seismic, and the upside from potential fracturing that we've seen on our 3D seismic could have on producing rates. We don't do not know that yet. But there are some wells that are being made run next to our acreage in both DeWitt and Karnes Counties, they're exceptional wells.

Any chance you can define "exceptional"?

You know, right, similar in between our Sinor and our Crawley.

That's helpful. One last question, and I'll hop off. Can you -- you mentioned in the prepared comments in the press release that you have a rich Eagle Ford production number. Can you tell us kind of as you build up to that 10% 4Q-over-4Q guidance number, what type curve are you assuming or maybe a 30-day initial rate in order to build up to that 10% 4Q 2010 versus the 2009 number?

Yes. The assumptions are really just running the two rigs that we currently have until the end of the year. So it does not include any ramp up, which we would expect to ramp up starting this summer with the JV, maybe to four, maybe to six rigs and then ramping on up to 14 by 2013. So both our fourth quarter 2010 number and our double-digit of 10 plus does not have any significant ramp up in Eagle Ford.

Okay. That's very helpful. Thank you.

Next we'll hear from Brian Singer with Goldman Sachs.

Thanks. Good morning.

Hey, Brian.

Going back to Spraberry with your cost mitigation effort. How much capital has been spent or do you expect to spend overall on purchasing on rigs and equipment and what has been spent so far, and what's expected to be spent in this year's budget?

Well, I think, if you take a look at what's needed in terms of tubulars, as well as, pumping units, sand, that's well over a $100 million worth of expenditures, we're lacking in advance. And of course, our campaign for 2011 is 700 wells is going to be somewhere in the neighborhood of $800 million. So you're locking in a component of it, relatively small total percentage.

And what do you expect to spend on purchasing the 10 rigs? What kind of and how much of that is in, if anything, is in this year, do you expect in this year?

I think the average is going to be approximately $2.5 million per rig, so that would be easy to guideline.

Got it. Thanks. And then going to the Eagle Ford on your slide 13, you breakout the locations you expect to drill over the course of the year. Can you add any color on what drove those locations versus any other and how many more you expect to drill after JV signed?

Yes, I think we're trying to look at about two-thirds of our acreage, Brian. So from our DeWitt County wells all the way down to McMullen, we're trying to get a pretty good handle on how perspective all of that is. That is why the 11 TCF gross number I gave out includes about 65% of our average, which we feel like is very prospective.

A lot of it has to do with what we see as we drill all of our database -- all the wells we've drilled through the Eagle Ford to the Edwards over the last several years. Our 3D seismic has a lot to do with it, the amount of fracturing has lot to do with it and also the liquids rich portion where we feel like roughly 70% plus of our acreage is in the liquid rich area. So it's a combination of all those areas, plus expiring leases, they're [prospective].

And would one assume that once you sign a JV you would end up drilling more on the gas window portion of your acreage or would you just drill, you're accelerating drill a little bit more to, I guess, the north on the Cummings Saint window?

It would be accommodation of both but I would say, if we feel -- right now 70% plus of our acreage is in the Cummings Saint rich window. So I would anticipate a lot of the drilling is going to be in the Cummings Saint window just because of that over the next several years.

Move on to Amir Arif with Stifel Nicolaus.

Thanks. Good morning, guys. Two questions. One, first of all, just on your balance sheet and your free cash flow, you are getting increase your CapEx and the cash flow is going to be like you guys laid out it could be 1, 13 depending on prices. How much of that free cash flow or would you be looking to put back in the CapEx budget?

Right now, as Tim mentioned, I think the previous questions were along the purchasing rigs, and we're also already purchasing inventory for Spraberry for 2011. That's why we alluded to the proceeds from the MMS, the deepwater refund. You can look at that as being used to help ramp up both the Spraberry and Eagle Ford.

For instance, the Eagle Ford ones our JV is announced, we'll be expected to -- we may or may not take any cash up front. It just depends. We don't need the cash as a lot of other people have done, picked up a third cash in their JV processes. So that will be one consideration. But we'll also be expected on heads up basis to at least participate maybe 20%, 25% of our interest heads up. So once the JV is announced, we will obviously address the CapEx budget at that point in time for the rest of the year.

Okay. But in terms of your currently debt level, sound like you guys are comfortable leaving that alone and you would be use the excess free cash toward JV spend that's rather pay for ramp up?

Exactly.

And second question, on the operating cost side, I mean, you have given guidance for Q1 and assuming, ignoring everything you can't control like electricity prices and other stuff, but as you go from 14 rigs to 24 rigs and that activity picks up. How comfortable are you in the ability to keep the operating costs in the same guidance range you've given for Q1 or the rest of 2010?

The operating costs, I mean, have nothing to do with the rigs, I mean, that's more [refining] costs.

Yes. But in terms of workover picking up and other activity picking up on the play --

Operating costs can be more driven by commodity prices and labor costs. So if commodity prices -- depending on where commodity is, okay, the gas prices in my opinion, natural gas prices U.S. stayed low. It takes the pressure off the cost. Now, what's interesting is that the Spraberry has already exceeded the rig count in 2008 levels even though the Permian Basin rig count has not in general, obviously its because there is over a 100 rigs now drilling in the Spraberry Trend area, including the Wolf play. So it exceeded, but we've really seen no price pressures.

A lot of finding -- a lot of people are starting to move in from around the U.S. into Midland Texas. So obviously people are hearing about the increased activity. So a lot of jobs are coming in and obviously with 10% unemployment rates, as long as, that stays high, I just don't see any pressure right now on cost. But eventually it may happen. I expect the rig counts -- we're going to add another 25 rigs just in the Spraberry.

One additional comment vis-a-vis operating costs is remember, as we continually ramp up drilling we're bringing on new IP wells relatively high rate in this context the life of the wells is the rate you see in the first year. And so we actually get a benefit in terms of millions of out cost to the extent we're actually ramping up and accelerating drilling.

Okay. That's make sense. Just one final question. What's the timing on completing the current DeWitt and Karnes County, Eagle Ford well?

It should be by the end of the first quarter. I would expect by the end of first quarter, early second quarter for us to do any reporting at that point in time.

Sounds great. Thanks, guys.

Our next question will comes from Leo Mariani with RBC Capital Markets

Good morning, guys.

Hi, Leo.

A follow-up on the eagle Ford. Just curious as to how long that Crawley well on production and how it's holding up in terms of what it's currently producing?

Yes, it's holding up obviously much better than expected.

We run tubing in the well and have actually reduced the flow due to the size of the tubing of 2 and 3/8 to about 9 million to 10 million a day. So it should produce at that rate for several weeks plus. So obviously it's been a very, very strong well, much better than expected.

Okay. Okay. I guess, assuming that, you know, the JV and you guys are successful and everything here in the second quarter, you get some ramp ups, and really in the second half. How do you think your position from an infrastructure perspective to be able to handle the additional rigs and production out there?

It obviously helps as more we find a dry gas window, we already, obviously have a system in place, obviously with our average drilling and our own infrastructure in place. So obviously allows us to process potentially our gas through our own system. So that's a big plus and we're in -- obviously, in talks with parties and regarding to the type of deals that we can make in regard to putting in either combination of our own infrastructure or their infrastructure in place. So we don't really seeing the issues, there is plenty of capacity in the area. And obviously now all the major midstream players are all vying for dominance in that Eagle Ford play. All the major players are all vying for dominance in that eagle Ford play.

Okay. You guys had mentioned, I think, in your press release that, in higher sustained gas prices, you guys would pick up the gas focused drilling. Just curious that what sort of sustained gas prices we would see out there?

All of our gas drilling in our three areas that we're not drill today are very economical at $5 gas, obviously $5 plus. And but obviously the focus right now obviously the best returns in the company is in the Spraberry , Eagle Ford, project like Alaska and Tunisia, that's where the focuses is. So it could be a few months before we pick up activity in

Okay. Okay. I guess speaking of Tunisia, you guys mentioned, hit rate in the next month or so to embark on a three-well program. Just curious as to whether or not you guys have any kind of sense of what the potential on the exploration side with the another program?

We get to significant in [present] wells. We feel like a two of our discoveries made in late 2007, early 2008 are much bigger than expected. So the two other wells were test have big these fields are.

And the third one is an exploration well. So obviously we're excited about the program, and should have results sometime in by June of this year.

Okay. Thanks, guys.

Our next question comes from Joe Allman with JPMorgan.

Thank you. Good morning, everybody.

Good morning, Joe.

In terms of the Eagle Ford, Tim, I think you said you're going to ramp up to 14 rigs by 2013 and it seems that that's contemplating the JV, so and its, is that correct? And then will your JV be a 50/50 JV such that 14 rigs gross is really seven net to Pioneer?

Yes, Joe. It was me that talked about it. Yes, the 14 rigs and the 11 TCF and the 750 locations are all on the basis that's all gross in 100%. We would expect to sell somewhere between a third to half of our position in a JV. So it depends on how much we sell.

Okay. I appreciate that. And then, I know, Amir asked about free cash flow. In our model as we look out, especially in 2012, you're generating a bunch of free cash flow. What are you thinking about how to utilize that free cash flow?

Right now in our models it's all going into Spraberry. Because and in the Eagle -- in our Eagle Ford model with the JV partner where we're going to be getting a theory, and so it pretty much pays as it goes, so need from [treasury]. But this Spraberry model as I mentioned in 2011, we are going to be adding $300 million CapEx. So our cash flow goes up $300 million. In 2012 we go up another $300 million plus, and that's going up to 1,000 wells, so almost all of our increase cash flow is going to the Spraberry ramp up. Then eventually in 2012 plus Spraberry starts paying for itself essentially and start driving off cash flow. So we don't have huge amount of excess cash flow until 2013 and beyond. Okay.

Okay. And what price, I know you have a bunch of hedges, but what prices are you using for your model?

That's like a $80 and $6.

How many wolf berry locations do you have? Okay. Got it. Okay. Thanks. And in terms of Spraberry, how many Wolfberry locations do you have in inventory? And at some point that Wolfberry will it become the focus going forward?

We have several hundred in the Wolfberry, but I think, one of the things we have found out is that, we've finding out that the Wolfcamp is more prolific than we thought just inside the Spraberry. In fact, recent studies show that we're getting somewhere between 30,000, 35,000 barrels additional by going all the way into the deep Wolfcamp just in the Spraberry Trend area field.

So we're starting to see much better results in the Wolfcamp. Throughout the field we're essentially taking almost every well to the deep Wolfcamp in the Spraberry and so, as Tim mentioned about this 17%, I think that 17% on hold could get better. But we expect to see 17% better production as we are to better recovery, but a lot of it is a combination of the silt/shale and also going all the way down to the deep Wolfcamp.

Okay, that's helpful. And I know someone earlier asked about the rigs. I might have missed this. But are you buying new build rigs or you are buying used rigs and I know you said $2.5 million per rig. How much of that do you expect to spend in 2010 and how much in 2011?

Those are all existing rigs that are used rigs, very good shape, and taken out of existing inventory. You know, looking at 2011, those rigs are going to be in place. Most of the expenditure for the rigs will be in 2010.

O kay. That's helpful. Okay. That's helpful. And then just lastly, I think at the beginning of the call, I think, Scott maybe you said that's interest income from the royalty refund, $25 to $30 million. So does that mean that you have on an after-tax basis it's going to be $75 million-plus, something like $90 million after tax?

Yes. We'll use, as Scott mentioned, we'll use NOLs to show stockpiles and paying cash taxes associated since we have NOLs and we've been -- we expect the interest to come in some time later this year.

Okay. All right. Appreciate it.Thank you very much

Right. And I'll reflect it when we get the interest in.

Got it. Very helpful. Thank you.

Robert Christensen with Buckingham Research Group has our next question.

Yeah. Thank you. Great quarter. The joint venture, would you accept separate partners? Could it be a couple different dials or do you like to have just one player in the join venture?

I think our preference, you know, navy partners is obviously, you get to find the right one but maybe hard to find two or three. So we prefer one.

And are there any other benchmark joint ventures that we should look at to see what if you're getting more or less than someone else? I mean, I look at the Swift/Petrohawk joint venture. Are there other transactions that we should benchmark your joint venture off of to say whether it's better or worse?

I would look -- I would tend to look at all the shale play joint ventures that have been done in this lower gas price environment. So over the last 12 month, as a more of a benchmark, there's two or three private deals that haven't been -- that have been done or will be done here shortly in the Eagle Ford, and we're not exactly, we've heard some numbers that are much higher than the swift deal but we haven't confirmed them.

Okay.

But I would use these other shale plays, JVs that have been done as a benchmark over the last six to 12 months.

And let's maybe just spend a moment on your vision for the Raton, I mean, it's now a play that seems to be a little bit forgotten or on the way side for awhile here. I don't know what your thoughts are with the Raton?

Yes. I think on Raton, yes, on Raton, we had several hundred locations. Our preference is, at some point in time, is to treat it like we did the Spraberry several years ago. We were going to the deepwater Gulf of Mexico is drilling up wells to keep production flat. And we can do that for the next, right now it's declining somewhere between 5% and 7% per year, Raton. But there is enough inventory locations.And with good economics at $5 plus, that, I think our long-term goal is to drill enough wells somewhere around a 100 wells per year and keep Raton flat for the next several years and use excess cash flow to go into this Spraberry Trend area and the Eagle Ford plays.

So you're idling now in the Raton, if you will, does it --

Yes. We are not drilling in Raton.

Very good. Thanks, Scott.

Next we'll hear from Michael Hall with Wells Fargo.

Thanks. Thanks. Pretty well covered at this point. But one quickly on the Spraberry. As you look at that 425 locations in 2010, 700 in 2011, 1,000 in 2012 and beyond, how many of those are PUDs that are on the books today?

Today we have about 3000 PUDs on the books, 3300, somewhere in that neighborhood. So you'll see a mixture of PUDs and unbooked drilled, but I would say, probably at least half of the wells drilled in that time period will be PUDs.

Okay. That's helpful. Okay. That's helpful. And then, on the current -- in the currently reserve in the Spraberry, are there any Wolfcamp bookings or how much of that is Wolfcamp?

Yes, Wolfcamp, at this point in time, we have not added significant amount of reserves from our Wolfcamp, what we've seen over the last few months. So that's obviously a huge up side that we see over the next several years.

Yeah. Okay. Great. Okay. Great. And then quickly in the Eagle Ford, I think Mike Jacobs may have asked, but you said your current 10% year-on-year 4Q 2010 versus 4Q 2009 assumes two rigs running in the play. Can you give a little more color on the assumed well production profile on those in the guidance?

No. I would tend to look, the only, we don't have -- we have 90 days' history on one well and about 30 days on another well that the only type curves that are out there is to track Hawk well -- Petrohawk wells.

Okay. Is that generally what you're doing there?

Yes, that would be my suggestion.

Is that what you guys are doing?

Yes.

All right. That's it. Thanks very much.

That's all the time we have for questions today. I'll turn the call over to Mr. Frank Hopkins for additional or closing remarks.

Hey. Thanks everyone for being with us this quarter. If you have any follow-up calls, myself, Matt Gallagher and Norman [Batters] will be around this afternoon.

That does conclude today's conference. Thank you for your participation.