Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Executives

Frank Hopkins - Vice President, Investor Relations

Scott Sheffield - Chairman and Chief Executive Officer

Tim Dove - President and Chief Operating Officer

Rich Dealy - Executive Vice President and Chief Financial Officer

Analysts

Dave Kistler - Simmons & Company

Michael Jacobs - Tudor, Pickering, Holt.

Brian Singer - Goldman Sachs.

Amir Arif - Stifel Nicolaus

Leo Mariani - RBC Capital Markets

Joe Allman - J.P. Morgan

Robert Christensen - Buckingham Research Group

Michael Hall - Wells Fargo

Pioneer Natural Resources Co. (PXD) F4Q09 Earnings Call February 3, 2010 10:00 AM ET

Operator

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 Power Point 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 and may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer’s news release on page 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.

Frank Hopkins

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 then cover the fourth quarter financials in more detail and provide earnings guidance for the first quarter of 2010. And after that as usual, 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. Appreciate the time, effort by taken to listen to our quarterly call. We’ll start on slide number three on highlights. For the fourth quarter ‘09 we had adjusted income of $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 a -- 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 about $25 to $30 million, which will book at a later day. We’ll use 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 102,000 barrels a day. That reflect more production curtailment of about 2,500 barrels per day due to longer than anticipated maintenance, shutdown of our detail facility in South Africa that processes gas to liquids. We did receive -- we’re back to full production resumed in early January for this project.

We produce 115,000 barrels of oil equivalent per day in 2009 and we’re up 5% on a per share base versus 2008, 3% absolute, despite a very curtailed drill program of going from 30 rigs to 1 rig during the year.

From a reserve standpoint, we added proved reserves of 52 million BOEs equivalent or 115% of full year production from drilling success and performance improvements.

Drillbit finding costs of $7.42 for BOE excluding price revisions and an oil and finding cost of little over $9, excluding price revisions. During the year we reduced debt by up to little over $200 million. A combination of the Gulf of Mexico shelf properties, dropping down into the MLP of PSE and showing free cash flow during the year.

In addition during the quarter, we did issue $450 4 million or 7.5% senior notes to reduce our credit facility indebtedness. As we’ve 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, 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 sometime in 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 1750 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 group production growth starting in 2011.

Turning to slide number four, returning to quarterly production growth in first quarter of 2010, again, as you can see we’re already ramping up first quarter of 2010 with our estimate of 112 to 117,000 barrels a day equivalent.

We’ll be ramping 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 have already press release reported year-end reserves of 899 million barrels oil equivalent, I mentioned earlier we had 52 million barrels oil equivalent. Primarily successful drilling in the first part of the year and also improved performance, we did have a 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 recovered most of that back and we’ll talk about what happens at $6 flat.

We are all set by Ad Valorem natural gas revisions of 14 million BOEs equivalent that was run at a price little bit over $60. As I mentioned we recovered 98% of our Raton revisions at $5 flat NYMEX gas price.

We would add 81 million barrels of oil equivalent, a gas reserves at $6, which is more reflected of stripped gas price, more than a 100% of 2009 negative gas provisions and 18 million barrels of oil equivalent of liquids at $80 flat, as you can see in the table.

We had a PV 10 of $93 billion before tax at $80 in $6 flat. Obviously 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 is obviously fairly easy for us to drill our PUDS within a five-year timeframe. So we decided obviously to go within the five-year, which is a guideline right now within the SEC.

Our Spraberry PUDS are also within one offset PDP location, obviously, we noticed several people are booking two and three off-set locations away, we decided at this point in time not to do.

Looking at the table, you can see, obviously, the Spraberry is still have the company. It’s pretty much stays around 5 million barrels, if you look at both cases whether it’s in $62 and $380 or $80 and $6. Raton we see a big pickup obviously $6 gas. The rest of the assets stay fairly close to the same. Well, we would get up close to a 1 billion barrels of crudely reserves at $80 and $6 flat.

Turning to slide number six, very strong F&P performance, again, oil and finding costs a little over $9, excluding price revisions, and a drillbit finding cost a little bit over $7, excluding price revisions, a significant improvement versus 2008.

Reserve mix obviously staying at -- we are predominantly liquids, 98% in the U.S., 54% liquids. Obviously with our mix of -- 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 crude develop percentage obviously continue to go up. Our ratios of crude reserves to production are 20 years with our approved develop 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 a recent strip, obviously the strip came down over the last two-three weeks, but over the last three-four days it’s going back up. Obviously little bit over $1 billion, so we are still expecting around a $1 billion of cash flow for 2010, then spending somewhere between $800 to $900 million of CapEx with 90% of it oil focused. We’ll talk a little bit more about the ramp up in Spraberry, also on other areas, with Tim in a second.

In addition, with our three ways obviously we have upside up to about $1.3 billion that we see any type of increase in prices. And also in addition with the 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 those proceeds to help support and ramp up Spraberry and Eagle Ford ramp up.

Turning to slide number eight, 2011, again, the cash flow significantly picking up from about $1 billion cash flow up to about 1.3 billion, with our three ways at $99 up side and $870 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 then ramping up over 700 wells during 2011.

Finally, on the last slide before returning over Tim, slide number nine, why invest in PXD, obviously we have one of the largest inventories with over 20,000 locations, potentially up to 750 locations in Eagle Ford and other locations throughout our asset base. The focus is over 75% liquids. So, obviously, at a point where oil is trading 15 to 16 to 1 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 looking in prices for the next two years.

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. And also the excitement about 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 positions through 2012. We’ve done more hedging in ‘011 and ‘012, with the recent run up about (inaudible) in regard to the commodities, which gives us upside $99 in 2011, with downside protection and also up to $120 in 2012, with 870 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 almost our drill focused on liquids. And obviously, again, we’re blessed with a low -- very decline asset that delivers very stable cash flow.

Let me now turn it over to Tim.

Tim Dove

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.

And 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 occurred when we were starting up drilling. We’re starting up a significant workover program to take advantage of relatively high commodity prices and that’s the starting point for a significant growth trajectory we’ll talk about on the next side.

We only drilled 48 wells last year, that’s maybe an all-time low for Pioneer but that said, we’re embarking upon a significant ramp up in fact plan to drill about 425 wells this year.

We’re on schedule from a rig standpoint, we’ll have 14 rigs running here shortly in February, and on schedule to have the 19 rigs in place by mid-year and 24 at year-end, heading towards a 700-well campaign at 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. And the returns are still magnificent really, 50% plus IRR before tax.

The costs of return to essentially an equivalent levels 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 water plug in the second quarter and we’ll be looking for production impacts from that project somewhere in the neighborhood of 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 and you can see, as we begin the manufacturing process of oil development in this field, we can grow up to about a 20% figure by the implementation of the rig schedule shown at the bottom, some 425 welts being drilled this year, 700 2011, and getting up to 40 rigs, which would drill approximately 1000 wells in 2012. It’s clear that we can increase potentially above 40 rigs, but that’s just a large target of 1000 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 it’s 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 manufacturing process, and really in the context of all resource plays, it’s very critical to be protective of margins and lot of the steps we’re taking are an effort to mitigate potential costs creep and to further vertically integrate our operations provide some of oil companies operate services in this Spraberry as our drilling ramps up.

We really have yet to see any cost creep in the Permian Basin, but the idea here is to foreshadow any potential further increases in costs we’ll met again by company own facilities and equipment. And toward that end, we have announced, we’ll be purchasing approximately 10 rigs, which if you think that in the context of 40 well program in 2012 would cover some 25% of our drilling program.

We announced a time our inventory pulling units now at about 18. At any given time in the field we have about 30 pulling units working. And those given us significant cost saving especially in the peak market rate we saw in 2008, some 40% less than market is the cost at which we can operate those facilities. And that is -- those acquisitions we are pulling in have essentially already paid out.

We have transferred a frac fleet down from Raton to work in the Permian Basin and each of these frac fleet can frac some 225 wells per year and 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 suffices 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 suffices to say 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 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, I mentioned, well, 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 already 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 Counties where we’re really focused on our liquids rich acreage. A substantial amount of our acreage is actually in the liquid-rich band shown here in the intermediate sections 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 number 5 and Sinor number 1 have given us a lot of confidence in terms of the kind of rate the wells can make, particularly the Sinor number 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 and even if we are drilling wells in the dry gas window, we feel like we can do so at rates that will be, you know, highly economic.

And by virtue of our three (inaudible) 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 technology leader when it comes to the application of all these -- all the data we have acquired over the years.

So we continue to be very excited about what we’re seeing at Eagle Ford Shale. I think, it needless to say, its an important project for the company and we’ve got a great team and people now working on the Eagle Ford Shale and look forward to the joint venture deliberations.

So that concludes my slides, of course, in Pioneer we have many other assets contributing to our operational successes, and they are captured in supplemental slides that are attached at the end but let me make a couple of comments about couple of our areas.

Alaska for instance we as you know we have a continuous drilling program going in Alaska with one rig running, it will be the subject of drilling several wells 2010, including two (inaudible) slotted wells for the winter and then 5 (inaudible) wells in the summer, as well as, testing in new zone here shortly that has yet to be tested. Suffice it to say, Alaska, by virtue of the results these wells will be an important component of our growth in 2010.

And in Tunisia, we have a three well operated package that will be commencing probably looks like now in March, and we’ll have also approximately three non-operating 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 base-line 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.

Rich Dealy

Thanks, Tim. Turning to slide 14, net income attributable common stock 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 get 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 to you that was MMS refund, that is including 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 our 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 down time of the non-operative GTL plant in South Africa, production costs, I’m going to talk about a little more detail on a couple of slides later.

Exploration and abandonment came at the lower part of the range, primarily just geo science work and a little bit of acreage cost. DD&A, below the guidance, two items really causing that, one, reserve base that Scott talked about adding to our reserve base at year-end those came on in the Q4 so that got the rate down.

In addition, South Africa production being down, it’s one of our lower operating cost assets, but one of our higher depletion assets and 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 of bonds that we issued in November, so that incremental interest expense being in there. And then the rest of the items here all were within our range of expectations, so nothing unusual there.

Turning to slighted 15, price realization in quarter we did benefited from higher prices, you can see in 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, good improvement in terms of price realizations for the company.

At the bottom, there are 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 to hedges that were in place at that point in time. And the second right at the bottom, shows the derivative impact these prices that is not including in price, [we trying to give] 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 done -- the team has done a tremendous job in reducing overall production costs. You can see relative where we’re in the fourth quarter of ‘08 versus the fourth quarter of ‘09, down about 22% or $3.25 per BOE.

We’ve talked about lot of these items in past quarters. So I’ll focus more my comments on the third quarter comparison to the fourth quarter and point out a couple of unusual items that it in the fourth quarter.

One, we did have higher workover expense for BOE in the fourth quarter, that truly impact of higher oil prices and we increase our workover activity to restoring production on some repair and production in Ad Valorem Taxes line item it is lower in the fourth quarter reflecting tax refunds we did apply during third quarter, fourth quarter, for some gas wells that qualify for high-cost tax funds, 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 production cost, and so the weighted average without that production cost that average to be up slightly. We also had little bit of increased field maintenance in the fourth quarter.

Turning to slide 17, switching gears, talking 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 to $48, up slightly from prior periods, once again reflecting the incremental interest associate to bonds that we issued. We have swapped a big chunk of those bonds back to floating it’s running through our derivative activities as well.

Other expense, we’ve had a number of people who asked us to start giving some guidance on that. So we added that in here at $12 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-control interest are consistent. The non-control 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 comment. As Tim mentioned, our number of slides in the back in the supplemental information, I do encourage everybody to look at, 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.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And our first question today will come from Dave Kistler with Simmons & Company.

Dave Kistler - Simmons & Company

Good morning, guys.

Scott Sheffield

Yeah. How are you doing, Dave?

Dave Kistler - 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?

Tim Dove

Yeah. 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.

Dave Kistler - Simmons & Company

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 ‘11 and ‘12. 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 ‘11 and ‘12?

Tim Dove

Yeah. 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.

Dave Kistler - Simmons & Company

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?

Tim Dove

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.

Dave Kistler - Simmons & Company

Okay. That’s helpful. And then, I guess, you know that, somewhat reflected in Q4 ‘09 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?

Scott Sheffield

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, this 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 surprise with that conclusion.

Dave Kistler - Simmons & Company

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

Operator

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

Michael Jacobs - Tudor, Pickering, Holt.

Thanks. Good morning, everyone.

Scott Sheffield

Michael.

Michael Jacobs - Tudor, Pickering, Holt.

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?

Tim Dove

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.

Michael Jacobs - Tudor, Pickering, Holt.

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?

Tim Dove

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.

Michael Jacobs - Tudor, Pickering, Holt.

Any chance you can define exceptional?

Tim Dove

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

Michael Jacobs - Tudor, Pickering, Holt.

That’s helpful. And one last question, 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?

Tim Dove

Yeah. 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.

Michael Jacobs - Tudor, Pickering, Holt.

Okay. That’s very helpful. Thank you.

Operator

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

Brian Singer - Goldman Sachs.

Thanks. Good morning.

Scott Sheffield

Hi, Brian.

Brian Singer - Goldman Sachs.

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?

Rich Dealy

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 $8000 million. So you’re locking in a component of it, relatively small total percentage.

Brian Singer - Goldman Sachs.

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?

Rich Dealy

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

Brian Singer - Goldman Sachs.

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?

Scott Sheffield

Yeah. 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 perspective.

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 under protective.

Brian Singer - Goldman Sachs.

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?

Scott Sheffield

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.

Brian Singer - Goldman Sachs.

Great. Thank you.

Operator

Move on to Amir Arif with Stifel Nicolaus.

Amir Arif - Stifel Nicolaus

Thanks. Good morning, guys. Just 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?

Rich Dealy

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 instances 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.

Amir Arif - Stifel Nicolaus

Okay. And 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?

Rich Dealy

Exactly.

Amir Arif - Stifel Nicolaus

Okay. 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 ‘10?

Rich Dealy

The operating costs, I mean, I have nothing to do with the rigs, I mean, that’s more finding costs.

Amir Arif - Stifel Nicolaus

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

Rich Dealy

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.

Tim Dove

One additional comment vis-à-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.

Amir Arif - Stifel Nicolaus

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

Tim Dove

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.

Amir Arif - Stifel Nicolaus

Sounds great. Thank, guys.

Operator

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

Leo Mariani - RBC Capital Markets

Yeah. Good morning, guys.

Scott Sheffield

Hi Leo.

Leo Mariani - RBC Capital Markets

Can you follow-up here 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?

Scott Sheffield

Yeah. It’s holding up obviously much better than expected.

Tim Dove

We run tubing in the well and have actually reduced the flow due to the size of the tubing of 2, 3 and 8ths to about 9 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.

Leo Mariani - RBC Capital Markets

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?

Scott Sheffield

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.

Leo Mariani - RBC Capital Markets

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 that sustain gas prices we would see out there?

Rich Dealy

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 those areas.

Leo Mariani - RBC Capital Markets

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?

Scott Sheffield

Yeah. 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.

Tim Dove

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.

Leo Mariani - RBC Capital Markets

Okay. Thanks, guys.

Operator

Our next question comes from Joe Allman with J.P. Morgan.

Joe Allman - J.P. Morgan

Thank you. Good morning, everybody.

Scott Sheffield

Good morning, Joe.

Joe Allman - J.P. Morgan

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?

Tim Dove

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.

Joe Allman - J.P. Morgan

Okay.

Tim Dove

So it depends on how much we sell.

Joe Allman - J.P. Morgan

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?

Rich Dealy

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 ‘011, 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 a thousand 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.

Joe Allman - J.P. Morgan

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

Rich Dealy

That’s like a $80 and $6.

Joe Allman - J.P. Morgan

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?

Rich Dealy

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, 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.

Joe Allman - J.P. Morgan

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?

Scott Sheffield

Those are all existing rigs. That are used rigs. Very good shape. And taking 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.

Joe Allman - J.P. Morgan

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 plus, like 50 -- something like $90 million after tax?

Rich Dealy

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.

Joe Allman - J.P. Morgan

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

Scott Sheffield

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

Joe Allman - J.P. Morgan

Got it. Very helpful. Thank you.

Operator

Robert Christensen with Buckingham Research Group has our next question.

Robert Christensen - Buckingham Research Group

Yeah. Thank you.

Scott Sheffield

Hi, Bob.

Robert Christensen - Buckingham Research Group

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?

Scott Sheffield

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.

Robert Christensen - Buckingham Research Group

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?

Scott Sheffield

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.

Robert Christensen - Buckingham Research Group

Okay.

Scott Sheffield

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

Robert Christensen - Buckingham Research Group

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?

Scott Sheffield

Yeah. I think on Raton, yeah, 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.

Robert Christensen - Buckingham Research Group

So you’re idling now in the Raton, if you will that mean does it…

Scott Sheffield

Yes. We are not drilling in Raton.

Robert Christensen - Buckingham Research Group

Okay. Very good. Thanks, Scott.

Scott Sheffield

Okay, Bob.

Operator

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

Michael Hall - Wells Fargo

Thanks. Pretty well covered at this point. But one quickly on the Spraberry. As you look at that 425 locations in 2010, 700 and 2011, 1000 2012 and beyond. How many of those are PUDs that are on the books today?

Tim Dove

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.

Michael Hall - Wells Fargo

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?

Scott Sheffield

Yeah. 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.

Michael Hall - Wells Fargo

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 ‘10 versus 4Q ‘09 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?

Scott Sheffield

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.

Michael Hall - Wells Fargo

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

Scott Sheffield

Yeah. That would be my suggestion.

Michael Hall - Wells Fargo

Is that what you guys are doing there?

Scott Sheffield

Yes.

Michael Hall - Wells Fargo

Effectively.

Scott Sheffield

Yes. Pretty close.

Michael Hall - Wells Fargo

Okay. All right. That’s it. Thanks very much.

Operator

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

Frank Hopkins

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

Operator

This does conclude today’s conference Thank you for your participation.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Pioneer Natural Resources Co. F4Q09 Earnings Conference Call
This Transcript
All Transcripts