先鋒自然資源 (PXD) 2011 Q1 法說會逐字稿

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

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.PXD.com. At the website, select Investors, then select Investor Presentations.

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

Thank you, Shannon. Good day, everyone, and thank you for joining us. I'm going to briefly just go over the agenda for today's call.

Scott is going to be the first speaker, he will provide the financial and operating highlights for the first quarter of 2011. He'll then comment on the Company's production outlook, capital program, and cash flow forecast for the 2011 through 2013 period. After Scott concludes his remarks, Tim will update you on our drilling results and plans, with particular focus on the Spraberry, the Eagle Ford Shale and the Barnett Shale combo play. Rich will then cover the first quarter financials in more detail and provide earnings guidance for the second quarter. And then after that we'll open up the call for questions. So, Scott, I'll turn the call over to you.

Thanks, Frank. Good morning. We appreciate everybody's time to listen to our first quarter call. Again, we had an excellent quarter. First quarter 2011, adjusted income of $81 million or $0.68 per share. It does exclude our gain from our -- primarily from our Tunisia sale that happened in first quarter and also unrealized market-to-market derivative losses of $164 million, primarily due to the run up of both gas and crude.

Production, drilled over 111,000 barrels of oil equivalent per day, primarily impacted by the cold winter, related down time and Mid-Continent, Spraberry and Raton about 2,000 barrels a day, and also unplanned third party down time in Mid-Continent, Alaska and South Africa of about 1,500 barrels a day. Our Spraberry program is on track and expanding. We're already operating 32 rigs, on track to be at 35 by mid-year, and stating that we'll be at 45 by the end of this year going into 2012.

We're operating 4 frac fleets, increasing to 6 frac fleets this month, 7 at year end. I think the important point of increasing these frac fleets, we have finally got on most of our frac fleets in both Spraberry and Eagle Ford, which you will see, Tim will go into great detail about the number of wells completing increasing significantly, going into the second, third and fourth quarter of 2011 in both Spraberry and also Eagle Ford.

Our early 20-acre well production is exceeding expectations, so 110,000 type curve we've come out, we're already seeing significant increases in expectations and I think we only had about 3 wells that went to the Strawn, so most of it is due to the Spraberry, shale zones and the Wolfcamp is causing the production to exceed expectations of the 110 type curve. Also, our Strawn wells are continuing to add significant production and reserves. We're now completing our first 2 Atoka wells, Tim will talk more about those.

And then finally, as we are have stated the last several weeks, we have an R&D program to test about 4 different zones in the both the Spraberry and the Wolfcamp, of horizontal wells. We're releasing information on our first 2 wells. The carbonate well, we frac'd out a zone and came in about 100 barrels a day. Frac'd out a zone in that well, obviously we're going to drill 2 or 3 more wells in various areas in the carbonate. And then our second well, I'm very highly encouraged the fact that just after about 10 days it's producing 150 barrels a day, still producing 1,000 barrels a day of load water with strong flowing pressure. We are planning to drill another 6 to 8 wells primarily this year. We'll continue that program going into 2012 and the long-term goal in the next 2 years is drill 3 to 4 wells, what we call a pilot program, in each of these 4 key zones.

To date we have not seen any evidence at all from other operators. Obviously from our sales it's too early, from other operators that are testing horizontal Wolfcamp wells that exceeds our vertical program of 50% returns in our vertical program of 700 wells this year and close to 1,000 wells next year.

Eagle Ford Shale production ramping up. We're operating non-rigs on track to be at 12 rigs by mid-year. Again, we initiated two frac fleets in April, Tim will go over great detail, you'll see the significant number of wells that will be completed and put on production over the next 3 quarters. Expect to be at 3 frac fleets by year end.

Barnett combo play with 2 rigs running, very consistent with our type curve of about 320,000 barrels of oil equivalent. We've already drilled 24 wells drilled, 5 are producing with excellent results.

Again, to remind everybody, we closed our sale of Tunisia for $866 million. Proceeds will be used to redeploy to core US assets, primarily Eagle Ford and Spraberry ramp up over the next 3 years. Again, a great strong balance sheet with debt to book going down to 31% at the end of first quarter for 2011.

Going to slide number 4, next page, still targeting 18% compounded annual production growth. We're confident that we're going to hit that number over the next three years. We're also confident that we're going to hit our range of 125,000 to 130,000 barrels. It's primarily due to the significant ramp up of bringing on these frac fleets. In second quarter continuing to increase those and seeing their significant completion ramp up primarily both in Eagle Ford and Spraberry.

Guidance for second quarter 116,000 to 121,000, so a significant increase from the first quarter and obviously again significant increase going into the second half of 2011. Liquids production continued to increase going from 44% up to 55% by 2013.

Going over our CapEx. Drilling capital still at $1.6 billion, obviously primarily focused on the Spraberry trend area field. Vertical integration facilities is about $200 million, we'll be completing most of that this year. Again, capital program funded primarily from the cash flow of about $1.5 billion and using about $300 million of Tunisia sale proceeds.

Slide 6, again due to the fact we're bringing on high liquids, much higher margin by increasing our liquids production cash flow significantly aids our growth, but we're going up to $2.1 billion for 2012 and up to $2.6 billion as shown on slide 7 for 2013. When you put that together, we're over 30% compounded growth rate, over since 2010 to 2013. As we have stated, our CapEx will be close to these numbers going into 2012 and 2013. The increase primarily due to the Spraberry ramp up in 2012 and due to the fact that the Carry and Eagle Ford will go away; during the first quarter of 2013 we will be picking up our share in the Eagle Ford play.

On the last slide on slide 9, again we have over 20,000 drilling locations. Obviously that number will go up with the success we're seeing in the 20 acre drilling. Right now we're just putting out the number of high graded twenty's but with the twenty so far exhibiting greater than 110,000, that number will continue to go up over time. Again, tremendous acceleration, drilling, and completing in the Spraberry and Eagle Ford shale zones, the redeployment of our proceeds allows us to accelerate even further. Again showing 18% compounded growth rate for '11 through '13 and cash flow growth of 30% plus during that same three-year timeframe.

Again, attractive. Hedging positions and vertical integration allows us to protect our margins. Again, we're ending the quarter with a very strong financial position and great balance sheet. Let me turn it over to Tim to go into more detail of our operations.

Thanks, Scott. Here at Pioneer, we continue our heavy focus on execution, and it is now paying great dividends that we entered the strategy of vertical integration a couple years ago. Because it is now the case that we're increasing our control of our own destiny, and as Scott has already mentioned, we've accomplished a lot in terms of adding frac fleets. One year ago for instance we only had one frac fleet, and as he mentioned a minute ago, we'll have six here during May operating on behalf of the Company. In addition to which we've added quite a number of dedicated fleets. So we're well on our way to see a very significant ramp up in wells put on production. I've got some very detailed slides on that coming up, and that will lead to a substantial increase in production, particularly as we ramp up in the second half of this year.

I'll start my commentary on slide 10 with a discussion of the activities in the Spraberry field in the Permian Basin, where Pioneer has the dominant position in the basin. We have about 50% of the acreage in the Basin and the vast majority of that is held by production. What we continue to observe is a big field getting bigger as a result of our activity, and that will continue with some 20,000 drilling locations ready to drill. We're the most active operator in terms of rig count in the Permian Basin.

Turning to slide 11, and this is covering some of the comments Scott made on the deepening program. We're in the position right now we can start to compile some definitive results that we are in fact significantly enhancing our rates and EURs by virtue of deepening the Spraberry wells.

So firstly, let's talk about the Strawn. The Strawn of course sits directly below the Wolfcamp. We've now completed 38 vertical wells in the Strawn over the last 5 quarters or so. That last 200 feet that it takes to drill into the Strawn only costs about $60,000 to drill, of course in addition to which is 1 frac stage. And what we're seeing is very substantial in the sense that the results indicate that we're getting about a 20% increase in first year production compared to wells that are TD'ed within the wolf bury itself. In terms of EUR contribution, we believe it is in the neighborhood of 20,000 to 24,000 BOE that we're adding in terms of Strawn. In terms of the prospectivity, we believe it covers about 40% of our acreage and about 50% of this year's program will target into the Strawn.

As for the Atoka, we're just starting up an Atoka program. It sits below the Strawn. It calls for us deepening the wells another 500 feet such that it sits about 700 feet below the Wolfcamp and that will add about $500,000 to $750,000 per well. The plan of course is to drill a series of Atoka wells. We're completing our first 2 wells as we speak. After testing those wells we'll later co-mingle the Atoka zones with the upper intervals of the traditional zones to be perf'd and completed in Spraberry typical wells including the Wolfcamp.

What's happening of course is the idea of adding substantial reserves also applies to Atoka and in this case we believe based on some deepened well data from offset operators in the area, there is a possibility to add something in the neighborhood of 50,000 to 70,000 barrels of incremental EUR to the deepened well, so that gets your attention. As a result, we plan to test about 10 to 20 wells into the Atoka during 2011 and of course we'll be reporting more about that as we see the well results. In summary, our well deepening in the Spraberry trend area is showing excellent potential and EURs.

Turning to slide 12, here is an update on 2 existing projects, our 20 acre down spacing as well as our water flood. We drilled 18 wells in 20-acre locations in 2010, 14 of those are on production. Importantly, only 3 of those were drilled to the Strawn, Scott mentioned that in his earlier comments. In essence, a lot of what I will talk about is really pay that's coming only from the lower Wolfcamp and upper zones as opposed to Strawn. Strawn has the potential to add even more, but what's very important to note is that the 20-acre drilling campaign we've seen so far is yielding results that are out pacing our old type curve.

The 110,000 BOE type curve that we had in place for 40-acre traditional Spraberry Dean drilling has now of course been increased to 140,000 barrels to include the Wolfcamp. Now we're exceeding that 110,000 barrel plan without in most cases completing into the Strawn, and that gives us a lot of encouragement about what 20-acre drilling can do now and the future. Accordingly we'll be drilling 20 wells or so in 2011 that will also be focused on more data for our 20-acre campaign, where we have some 13,000 future locations or more to drill.

The Waterflood project continues in the 7,000 acre pilot we put in place last summer. The production declines in that project area where we have over 100 wells producing continues to flatten and the early production response is being seen actually in quite a number of wells. This is working out quite well, we're very confident that we're seeing positive results out of this. It's a little bit early to give final results, because ultimately we're looking for uptick in production from the flooded zone, that being the upper Spraberry. The 20-acre drilling and the Waterflood project again are efforts that are focused on improving recovery efficiencies in the field going forward.

Turning to slide 13 and a discussion here surrounding the Wolfcamp horizontal activity, Scott has already covered some of this. Slide 13 shows the zones that are being targeted by various other operators, I won't go through these in detail other than to say that our wells as shown in green target the Wolfcamp carbonate and also the lower Wolfcamp shale. As Scott has already alluded to, we'll be testing several of these other zones including the Tippet Shale and the Jo Mill in future wells as we roll out our pilot project.

As to the results on these wells so far, that's covered on slide 14, the first 2 wells in our horizontal pilot program. Both of these wells were drilled with approximately 4,000 foot laterals, about 15 stages of fracs. We did have micro seismic in both cases such that we could monitor the fracs in each case from offset wells. As Scott has already mentioned, the first well IP is about 100 barrels of oil per day, but we did not have an effective stimulation as out of zone stimulation and as a result the production declined. We don't believe this is really representative of a test in this zone and likely we'll be drilling future wells to properly test the zone.

The second well which was as I mentioned a minute ago completed in the lower Wolfcamp shale is now in the process of unloading. The well is about 30% unloaded and we're seeing early test rates of about 150 barrels of oil per day. This well just so you know is naturally flowing up casing and actually it's starting to produce gas as well. As a result, the rate I mentioned a minute ago is really not an IP rate, that's simply an early test rate on this well. We'll be getting more information out when we finally IP the well after the flow back has occurred, it should take us quite a bit of time to have all of the water unloaded from the well.

We are going to continue a pilot program as Scott mentioned to drill several more wells in various different formations. This is an R&D project for us and so we're going to take quite a bit of time and effort and money to test various different zones and this will probably stretch well into 2012.

Turning to slide 15, I mentioned in my first commentary that this vertical integration business that we've entered is really adding a lot of value in today's world where these services are very tight and we're an industry leader in vertical integration which allows us to control costs and enhances our ability to execute. Today we have 14 of our own rigs working in the Permian out of a total of 32, for instance. We are significantly increasing our frac ownership as well as dedicated fleets and we have a bunch of our other supplies and materials in place on long-term contracts, including a new item where we're planning to contract our cementing services for the next 5 years.

All of this activity has the effect of saving significant amounts of money. In fact, the savings for the vertical well program is about $500,000 per well, which gives us a significant advantage in the total blended costs of our wells and then preserves the rate of return being approximately 50% before tax. We'll continue to take steps to mitigate execution risks wherever we can and to control costs and our vertical integration program is doing just that.

On slide 16, this is a lot of detail but it's a lot of granularity in fact on what we expect to result this year in terms of putting new wells on production. Ultimately this is the most important statistic about how our production should grow is how fast we put wells on production. It gives us confidence in our ability to accelerate production, because we have the fleets in place or they're coming and we have a very detailed plan to accelerate the number of wells put on production. We show it here by quarter as the new frac fleets come in, we get up to 35 rigs middle part of the year. We had frac fleets both in the second quarter, we'll be having some spot fleets added in the third quarter, and our fifth owned fleet adding to a total of 7 in the fourth quarter.

This gives us a lot of confidence then to point to slide 17 which shows the production effect. You can see really a dramatic increase in production. Our production is when we're in acceleration mode as we are both here and the Eagle Ford Shale, we have a back weighted result because we're just in the process of getting the fleets in place, getting the wells drilled, accelerating the number of wells drilled, so we have a back weighted second half weighted production growth in both of these key areas as we accelerate.

Ultimately we're confident in the 25% growth rate looking forward through 2013. You'll note on the bottom of slide 17 that we have a schedule for 45 rigs beginning 2012. Many of those rigs are already contracted, almost all of them are already contracted. They will be in place by the end of the year. We'll be at 35 here very shortly from 32 currently, so we're very confident in this asset. Again, we do not drill dry holes here. This is manufacturing oil and we have in place the processes to execute on the plan.

Turning now to Eagle Ford Shale slide 18, our operations are progressing very nicely there. We have 9 rigs running, we'll have about 12 here shortly by mid-year. All of the operations are going exceedingly well. We have a couple of new things in the slide here that we haven't discussed before, at least as to an earnings call, and that is that we are testing white sand as a profit in some of our shallower areas of the field, principally to the Northwest. We're drilling shallower wells, and the fact is if we can use white sand efficiently when it seems like some of the early results show that we can, we would have significant savings compared to ceramics, in terms of profit being used on these wells.

Our well performance continues as expected, in fact in some areas better than expected. Of course we're drilling up and down the trend here, not necessarily as efficiently as we will when we go to development mode and we can drill from individual pads a series of wells. Today we're still in the preservation of leasehold mode drilling up and down the acreage. But that gives us a great deal of confidence in the aerial extent and quality of the area we are. We still believe we're really in the sweet spot of the Eagle Ford shale.

We get a lot of questions regarding the Petrohawk wells in the Blackhawk area, which offsets a lot of Pioneer acreage in DeWitt. In fact, we're seeing well results that exceed our internal type curve for the high condensate yield area which this represents. We can confirm that Petrohawk's information as to how the wells are doing in that area, that's also being seen in our area as well.

We are ramping up our execution capabilities. As you know, we're a little bit slow getting some frac fleets out there in the first quarter, but we now have our own and a third party fleet operating at a high level of efficiency in the field. We have now 5 central gas processing facilities in place and we'll have 3 more done by the end of the year. What you'll see of course is just like we saw in Permian, a significant increase in the number of wells we put on production.

On slide 19 is the identical slide I showed for Spraberry, it shows the ramp up of wells we'll put on production in the Eagle Ford Shale and you can see that really is a reflection of initiating the new frac fleets. It's also related to getting the CGP's in place and what it leads to just as we see in the Permian is a significant acceleration both in wells put on production and therefore production itself, especially in the second half of the year. That specifically is shown on slide 20 where you can see a dramatic ramp up as the execution takes hold. In addition to which of course we're increasing the rig count, we'll be at 12 here shortly going to 14 is the current plan for 2012 and then 16 for 2013.

Turning to slide 21, I'll be brief about Barnett Shale. We're starting to see our first production results from the drilling campaign we began at the end of last year and we're very encouraged at what we're seeing. We currently have 2 rigs running. Out of the 24 wells that we've drilled, we have now 5 of those producing and we're seeing very good results. The last 3 wells we put on production, for instance, the data is shown here on the slide, averaged about 155 barrels of oil a day, 854,000 cubic feet per day. So really quite an excellent well result and we estimate that based on the type curve that we have in place that these wells are meeting or exceeding those type curves, which is going to yield in the neighborhood of a 50% internal rate of return based on current pricing.

Importantly, we have one of our own Company owned frac fleets that will be operational this month, and that will allow us then to again positively impact our growth as shown on slide 22, depicting production growth from the Barnett Shale and in fact what you see in Pioneer is a very heavy focus on execution. We have in place an excellent plan to execute in all of these critical areas. It's going to lead to substantial growth in production, both as we get later into this year and going into the next couple of years as well. In fact, in Barnett Shale we're looking potentially at even adding 2 rigs more in 2012 and 2013.

With that I will pass it onto Rich for a discussion of the financials and his outlook for the second quarter.

Thanks, Tim, and good morning. I will start on slide 23. As Scott mentioned, net income for the quarter attributable to common stockholders was $349 million or $2.96. Included in net income are three items worth noting. One as Scott mentioned we had unrealized mark-to-market derivative losses as a result of the increase in strip commodity prices of $164 million after tax or $1.40. We also recognized income from discontinued operations, this is predominantly related to the Tunisia sale and recognizing a pretax gain of $650 million, so after tax our all in discontinued operations was $415 million. We also had $17 million after tax from Alaska petroleum production tax credits for the quarter. Adjusting for those items and getting to a normalized earnings, we're $81 million or $0.68 per diluted share.

Looking at the bottom of slide 23, our guidance which does reflect our update we did in guidance in March for the weather impacts, if you look at our results you'll see each of the items came within guidance or on the positive side of guidance down that list. So an excellent quarter for the Company.

Looking at slide 24, the bars at the top represent our realized prices so these do exclude VPPs and derivative impacts. You can see that oil prices are up in the first quarter relative to the fourth quarter 12% to $89.43. NGL prices on same comparisons up 3% in the first quarter compared to the fourth quarter and gas prices are up 10% to $4.14 as compared to the fourth quarter of $3.76. At the bottom of the slide we do list out the impacts to pricing that we report from VPPs and derivatives, so they're there for your review.

Turning to slide 25, production costs, I'll spend a couple minutes here. First quarter production costs came in at $13.31 per BOE, this is up from the fourth quarter. But as we mentioned back in February, the fourth quarter had a couple of items in there that the biggest one being $10 million Alaska processing fee recovery that lowered our fourth quarter LOE by about $1 per BOE.

We also had ad valorem tax accrual adjustment in the fourth quarter that resulted in production taxes being lower. For the first quarter, a couple items there in LOE as we mentioned back in March, we did have a significant amount of repairs that hit in the first quarter to repair the damage caused by the severe weather, that's included in our base LOE. And as I mentioned on the previous slide with commodity prices up, our production taxes are higher in the first quarter.

Turning to slide 26, and talking about guidance here, production as Scott mentioned 116,000 to 121,000 BOEs per day and as Tim talked about the growth is significantly weighted to the second half of the year as we put on more wells on production during the second half. Production costs and really the remainder of the items listed here are consistent in fact with past quarters, so I won't go through each one individually, but they are consistent with past quarters and how we did in the first quarter. Why don't I stop there and we'll open up the call for questions.

(Operator Instructions) Scott Wilmoth, Simmons & Company.

Couple questions on your Company owned frac fleets that you are adding currently and later in the year. Do you have all the staff lined up and hired and trained to make those operational as soon as you get delivered?

Scott, actually this is Tim. We're in the process of hiring the staff related to the two fleets that are coming in the fourth quarter as we speak and training them on existing facilities. Our hiring has gone exceedingly well. What happens is people are very interested to work for an operator for a producer and certain ways more than they would like to work for a service company, and so we're getting excellent response and we're doing very well in terms of meeting our hiring plans.

Great. Then when I think about the second half ramp planned in the Eagle Ford, obviously you have got the frac fleets, you have got the people. Have you lined out transportation and gathering needs for that ramp?

Yes. In fact, we're working very hard of course because this is substantial amount of volume. We're working with various different parties on preparing for and being ready for liquids volume movement, in this case condensate. Of course our natural gas and rich natural gas in this case is spoken for because of three separate contracts that we have for off take, so I think we're in very good shape there.

Jumping over to the Spraberry, the Atoka you mentioned 50,000 to 70,000 additional BOEs per EURs that you're expecting. Is that in addition to the potential 20% up tick in the Strawn?

Yes.

Okay. If we think about we're at 140 potentially up 20% in the Strawn and then maybe another 50 to 70 with the Atoka, so ultimately we could be at 220 to 240 EURs with $2 million to $2.2 million well costs, or are we off on that?

I think those are relatively accurate realizing that remember, it's not applicable in every single acre in the Spraberry trend area, there's only certain acreage where that would apply where we have a combination of Strawn and Atoka.

And Strawn you said about 40% and then how much Atoka do you think is prospective across? It's too early to know?

It's too early. This is our first two wells, so we need to get a little data before we can really answer that specific question.

Brian Corales, Howard Weil.

I guess with only one frac fleet -- or now at two, how big of a backlog do you all have in the Eagle Ford, in terms of uncompleted wells?

Right now our frac bank is about 15 wells. We've been working into it on the basis of the Pioneer fleet and a third party fleet -- they have both been out there since April and they have been very efficient. We are going to be having a few spot slots available from other operators who haven't got their wells drilled in the second quarter. We don't really talk about that because we really talk about our dedicated fleets that's Pioneer owned and longer-term contracted fleets. But we are picking up additional slots here and there to be able to meet that put on production schedule.

In kind of with the ramp in both the Spraberry and the Eagle Ford, how much of the do you want to have Company owned or completion crews out there versus or how do you think about with the ramp? Are you going to be buying new ones or kind of leasing them out in the future?

I think we have stated -- in fact publicly we stated that the amount of vertical integration we do any given area somewhat depends on how tight that market is. For instance in the Permian Basin we're about 30% vertically integrated on rigs. There are rigs available. In the Permian Basin though, we're heading more towards about two-thirds vertically integrated on pumping services because it's so tight. Right now we're contemplating of course the delivery of additional frac fleet in Eagle Ford, which would put essentially two-thirds vertically integrated in the Eagle Ford as well by the end of the year, so that's kind of the rough percentages we're thinking about.

Okay, then one final question, I think you talked a little bit about it on your comments. In the Spraberry, how much of your drilling is holding acreage or is that pretty much mostly done?

It's relatively minimal in the overall scheme of things. We're drilling 700 wells or so. We probably drill somewhere in the neighborhood of 150 wells a year to hold production in one form or another.

Leo Mariani, RBC.

Quick question, kind of changing gears a little bit on Alaska. Looks like your Alaskan production has been dropping the past couple quarters and you talked about some well maintenance as well in the second quarter, which leads me to believe it might be down again. Just curious as to when you expect that sort of ramp up and what kind of growth you're expecting out of Alaska?

Yes, Leo. We've gone through the last 60 days re-completion program and some work over programs and we should see a pretty good bump going into second and third quarter of production. Also we'll be bringing on -- we just started testing our Tool Rock well and it's making over 900 barrels a day, that's that long lateral, the third zone. It'll be coming on here shortly, in fact just came on the last two or three days, we're testing that. So a combination of all of that, we should definitely see a bump, at least 1,000 maybe higher of net production.

Okay. In terms of the Atoka, you talked about deepening the wells. I think you were saying about $500,000 to $750,000 additional costs for roughly a 500 foot deepening. That sounded a little pricey to me. Can you walk us through the costs there? Is that all pretty much frac or how are you getting to that cost?

One thing we need, you may have mentioned or you may have seen in the slide there, Leo, is we do need an intermediate streaming casing because of the depth of those wells. By adding basically what amounts to 700 feet below the Wolfcamp, we're sort of at the limits of our traditional casing design, so we have to add other intermediate string, and that's really principally where the extra costs comes from. These wells are being drilled down roughly to 12,000 feet, so they're deeper than your traditional Permian Spraberry drilling.

Okay. Makes sense there. Just question on your NGL pricing. You talked about sort of a 3% sequential increase in fourth quarter and I think some of the benchmark prices like Mont Belvieu were up a lot more significantly. Was there anything going on there that sort of widens your differential at all in the first quarter we need to be concerned about going forward?

No. I don't think there is anything unusual by looking at it, just normal stuff, so nothing unusual jumps out.

Okay. Last question for you on the water flood in the Spraberry. Just curious as to how that's performing relative to internal model at this point in time and can you remind us how long you have been injecting water out there?

We started injecting I think it was in August last summer, Leo, and this is about the amount of time is takes as projected, at that time nine months or so before we start seeing significant impact. We've already started to see in production impact on individual wells. Remember, there is 100, 110 wells that are producing in that field, and so we've seen a select number of wells we've seen pretty significant increases in bumps to production. Importantly we haven't seen any significant watering out events that would give us concern. So overall it's going exceedingly well and we're very positive on it. It just takes time for the whole system to basically fill up with water which is what we're doing in a sense in this type of a water flood. It's going well. We need a little bit more time to see, ultimately we expect the field to increase production from the one zone that's being flooded which is the upper Spraberry.

Brian Singer, Goldman Sachs.

On the Wolfcamp Shale horizontal well with only 30% of the frac water unloading, can you put into context what you would expect going forward? Would you expect a materially higher oil rate or should we expect that any additional hydrocarbons coming out of the well from here to get to what would be a normal apples-to-apples IT will be more liquids rich natural gas, can you put where you are in this well in context with other wells completed this early on?

Yes, Brian. First of all, this is the first well drilled in the entire Permian Basin in this zone, so we have no other data. Secondly, our well is flowing, we are not using jet pumps. We could have used a jet pump and probably recovered the load water faster and got a much higher rate like some operators do. But this is just natural flowing.

So the gas/salt ratio is about 1,500 to 2,000 right now, so we're encouraged by the fact that it is very, very strong flowing pressure at the surface. Getting only 30% we ended up using over 100,000 barrels. So getting 30% back in probably roughly two weeks, less than two weeks, is very encouraging.

We tested this zone vertically over the last two years and essentially got 5 to 10 barrels a day out of this zone, initial rate. That's why we're opening this zone on all of our Spraberry wells now over the last two years. But getting 150 this early is semi-encouraging, but we're going to need rates much higher to pay out a $6 million or $5 million well cost.

But we're encouraged by it, we're going to drill several more.

In addition, the Tippet Shale, we're encouraged by what we're seeing there. There is a couple, two of the EOG wells out of about eight that I've seen production data on have come in about anywhere from 400 to 500 barrels a day. But that's why we're going to try the Tippet down towards the south where we have probably 100,000 to 150,000 acres, potentially to see what that does too.

Great. Thank you. Secondly in your comments you mentioned white sand proppant being used in the shallower Eagle Ford. Can you talk more specifically about cost savings potential there and how widely used could that could become or if that's just something that's very niche for the small portion of your acreage in shallower pieces?

Brian, of course as I mentioned most of the acreage we're talking about is in the Northwest part of the basin or at least as it relates to our acreage where it's a little bit shallower. Therefore with the less depth we have less pressures and accordingly sand becomes an alternative that makes sense. In fact the offset operators to the Northwest are using sand and with good success. What we've already seen is some pretty substantial positive results.

What it will save for us is about 60% on the cost of proppant, and as you know proppant in these wells can be well over $1 million, so I think so we're looking at a savings that could be in the neighborhood of $600,000 to $800,000 per well. To the extent it works, we think it could work on 20% to 25% of the acreage. We'll obviously be pushing that to see how much further we can move it to the south and east on our acreage as we get deeper because of that substantial savings.

Gil Yang, Bank of America Merrill Lynch.

If I could just follow up on Brian's question a bit. If you're using ceramic proppant on essentially all your wells right now, do you see a need, a definitive need for the ceramic proppant at this point or is it possible that your expectation of white sand on 20% to 25% is actually conservative?

I'll put it this way. We're marching to the south and east with white sand and see how far it works before we feel like we're going to have any degradation in results. One of the issues you face is the results only come at you slowly, it's hard to tell exactly in the short period of time that we have been doing it what the longer-term effects would be. I think we're going to use caution and make sure we don't go too far, considering we're getting down as we go into our south and east we're getting into 14,000 foot wells and very high pressure, so we have to be careful with it but we're going to be pushing the edge of the envelope.

Okay. Fair enough. The flow back on the second horizontal well, is it too simplistic to just say that as the -- as you recover more of the load water that the 1,150 barrels per day of total fluid recovery becomes more -- that stays at 1,150 but it becomes oilier? Or is it more likely that the water cut drops off but the oil component stays more constant?

Yes. We're hoping obviously, we've have had some rates up higher than the, on a per hourly basis, than the 150 barrels a day and we've seen that come up over the last two or three days, so we're encouraged by that. As we recover more load, we think the oil rate should continue to come up, and so that's what we think should happen.

Typically does the total rate drop off and then the oil rate come up or does --?

Yes, the total rate will come down because you're getting more and more of your load. Eventually you're going to leave a lot of your load back in, like we do in the Barnett and the Eagle Ford play. So any of these shale plays will you leave a lot of [load] water in the formation. We just don't know how much in this one zone in the Wolfcamp.

Okay. And the hydro carbons become a greater proportion of the overall flow back?

That's right.

Okay. In the carbonate horizontal, was there any particular reason that the frac went out of zone as you can tell?

Yes. We did not cement our liner in place, so basically most of the frac went near the well bore. So we did not get the frac essentially effectively stimulated out in the horizontal.

Okay. But you didn't cement it by plan?

We cemented the liners in the second well, the shale well, and that essentially allowed to us get an effective stimulation into all the various zones.

Okay. Does that tell you something about the azimuth of the well as well?

I don't know, Gil.

All right. Finally, in the Barnett the last three wells you said looked like they had pretty good rates. Presumably those last three wells are better than the first two wells. Have you learned how to do things better there and from a methodology perspective do you think the wells can be better going forward?

I think, Gil, as is the case with anything that these new projects we are trying some new ideas in terms of how to stimulate the wells and I think we've now done a better job of doing that. We had some issues on that in one of the first couple of wells, I would think these last three are more representative based on the learnings we've had.

Michael Hall, Wells Fargo.

You mentioned that you had some kind of comparable results I guess in DeWitt County relative to the Blackhawk field results. Can you give any color or any sort of statistics on recent wells in that area?

No. I think our main point is that we have a type curve, we keep detailed production data on those type curves and in that area they're way exceeding our type curve on the rich condensate, just like Petrohawk is stating. Our average -- we're staying with our overall average of 6 BCF equivalent. That includes dry gas, lean and rich condensate. But we're just stating in that high liquids area in DeWitt County that all of our wells there are exceeding our type curve.

I guess just moving quickly into the Permian, as you move deeper and continue with the deepening program, remind me does the mix, the hydrocarbon mix change meaningfully from interval to interval?

No. Pretty similar gas/oil ratio. So liquids is still going to be 90% in the Strawn and the Atoka based on our Strawn wells and other operators Atoka wells.

Joe Allman, JPMorgan.

Just a follow up on the Wolfcamp horizontal. I know you touched on this two questions ago, but about how much of the frac load water do you expect to get back? Is it somewhere in the neighborhood of 50% or could it be as high as 75% or more?

It's a guess, Joe, but the way it's going it could be 50% plus. In the Barnett we get 50% to 70% back, to give you an idea. Eagle Ford is 10% to 15% because of the higher pressures essentially evaporates down there.

Okay. That's helpful. And then in terms of the natural gas you're starting to see, are you seeing liquids-rich natural gas?

I have not seen a test, but it should be. 1,500 gas/oil ratio is about what the gas oil ratio is in a typical well in Midland Martin County and all the zones starting at about 1,500 gas/oil ratio. I would be pretty certain that it's 1,400 BTU gas.

That's helpful. And then in terms of this potential for the Wolfcamp horizontal, you've got the different intervals that you identified in your presentation. Are those intervals present throughout your acreage?

Essentially yes. It looks better in certain areas, like in for instance Martin Midland County is better we think for the lower Wolfcamp. The Tippet is better based on log data only than the southern part of our acreage. But we do have those zones throughout the entire Spraberry trend area.

Okay. Then in terms of your development or your testing of this play, are you staying in a geographic area and just trying to test the different intervals in a certain area, or are you kind of spreading out throughout your acreage and testing various intervals?

We're going to spread it out. The wells to the south will be -- I mean we'll drill some wells in the north that will probably be 100 miles apart. So these next six to eight wells and we'll probably drill another 5 or 6 and going into '12 we'll complete our program. They will be 30, 40, 50, 60 miles apart, as much as 100 miles apart.

That's helpful. And then if this play works, presumably you'd have to alter your vertical drilling. Because I imagine if this horizontal is more economic, you would focus on the horizontals and the Wolfcamp, but then I'm not -- how would you work out the vertical program at that point?

Most likely we would continue our vertical program and drill a series of horizontals. We'll have to work with the commission in Texas that regulates oil and gas in regard to how much acreage is dedicated to each, but we don't see a slow down at all in our vertical program. If we start one it will just be an acceleration on top.

Richard Tullis, Capital One Southcoast.

Scott, you had mentioned the well cost for the Wolfcamp horizontals. I guess it was $5.5 million to $6 million, those are the first two wells or is that like more of a --?

That's right.

Okay. So development mode it would be less than that?

Yes it would. Also depending on if we use any of our own rigs and our own frac fleets for that, it would have some savings also.

Okay. Just for reference point, what's the typical IP for Spraberry vertical?

Ignoring just Spraberry, Wolfcamp, they're coming in about 80 barrels a day now. They used to come in about 50 barrels a day with just Spraberry Dean, they're up on the on average 80 barrels a day Wolfcamp. Some of the Strawn wells we're seeing when we open up the Strawn get close to 100.

Okay. That's helpful. Thank you. When do you expect the next update on the horizontal program? When will you spud the third well?

We're not going to start our program until the third quarter. We'll dedicate 1 rig to the program and drill the series of 6 to 8 wells and probably add, it will continue I'm guessing into the second quarter of 2012. We want to put 3 to 4 wells in each of these R&D projects, in each of these 4 zones, so at the end of the day we'll have 12 to 16 wells total covering 4 different zones. It will take us a good year, but we'll release data as we get it.

Okay. That's helpful. Thank you. And as you come across more and more potential zones to access with vertical wells in the Permian, what's your outlook currently on potentially monetize and JV or outright sale of some of your acreage position in the Permian?

It will take us a minimum of two years to understand the deep rights, the deep potential of the Strawn, Atoka, and even there is deeper zones that our geologic team is studying below the Atoka. And then the horizontal program will be completed probably roughly in about a year or so, we'll need a good six months of production. So we're two years away from even thinking about JV'ing at that point in time, whether or not to accelerate any of our activity even further at that point in time.

Okay. All right. That's all for me. Thank you.

John Nelson, Macquarie Capital.

Good morning. Wanted to talk about the Spraberry. With seven frac crews at year-end, I was wondering what you think your quarterly well completion capacity in the play will be? Just looking at the slides it looks like you expect to add 225 wells a quarter, so towards the end of the year I'm just wondering how far above or how far above with 7 frac crews you might be able to go from there?

John, first of all, what's reflected in that draft is dedicated crews and that doesn't -- all of that is to say that we also have spot crews working. But to give you a frame of reference, in the early stages as we put our frac crews in place, they're averaging about 10 wells, a little over 10 wells per month, we're actually going to be going to 24 hour operations on our crews. We're seeing improved efficiencies through time. Our objective is to get maybe in the neighborhood of 12 to 13 wells done per month. If you do the math, that means that each frac fleet can do 150, 160 wells per year. That mean that with 7 crews working we're upwards of 1,000 wells, so we'll be relatively self sufficient even at the 1,000 well campaign going into next year.

Great. And then just one question on the Eagle Ford, to your comments about the wells and DeWitt County perhaps coming in higher than your previous guidance. Is that potentially why you have more confidence in sort of the 2011 production guidance and despite having some problems getting frac crews there now you still sort of maintain that number?

I think it really doesn't have much to do with DeWitt County wells as much as it is our overall program. We've got as you can see quite an amount of definition, quite an amount of granularity surrounding the frac schedule, the frac crews. What we don't show you on there is that there are several spot crews, as I mentioned in an earlier question, that we'll be utilizing on and off, especially in the second quarter. It really is more of the execution on our current plan that's yielding the production results that are shown on the Eagle Ford graph.

Great. Do you have an expectation for what your year end rate in the Eagle Ford will be?

It's pretty much set out. You can pretty much look at the second half production in the slide and look at the number of wells that are being completed.

Marcus Talbert, Canaccord.

Great quarter. Most of my questions have been answered but I did want to double back to the horizontal program. You mentioned with the one rig running and the wide area that you'll be testing in for the different intervals, is this just the amount of time taking getting the rig across these 50, 60 miles or is that what's causing sort of the time to test the full program for the year? Is there no reason it couldn't be accelerated further?

We can accelerate it, obviously with more rigs. But to me the -- I think the market, as I stated earlier, the market has gotten way ahead of the horizontal program. When you're getting 50% type returns on 700 wells and 1,000 wells on our vertical program, it's going to have to take tremendous results to get to 50% plus returns on the horizontal side. We just feel like since we have 40 to 50 billion barrels of oil in place in this field that it's important to test all of these zones over the next twelve months, so we're going to take our time about it. We're not trying to hype it as other companies are. And it's an R&D project. So we could run four rigs if we wanted to, but we're just going to dedicate one rig and we want to make sure we don't take away from our vertical program. We run four rigs, we'd have to take away from our vertical program. And most of our production is held by production, so we just want to do it methodically, carefully, and so that's why we're just dedicating one rig to the program. Which will take about a year to finish the program.

Understood, really appreciate that color. With these big number that you're talking about with the vertical program, understanding that just planning on drilling the 10 to 20 Atoka wells this year, is there any horizon beyond the Atoka that might be prospective for a test this year?

Not for a test this year, but we're definitely studying the next thousand feet below the Atoka.

Dan Morrison, Global Hunter.

Thanks, a couple quick questions. What are the well counts associated with your current outlook in the Spraberry and the Eagle Ford for '11 and '12?

Tim, do you have the exact number?

Let's see. Let's do Permian first, Permian 700 wells in 2011 right at 1,000 wells 2012. Eagle Ford we have approximately 100 wells we're drilling in 2011, the current plan for 2012 is not finalized but we're saying I essentially it's approximately 130 to 140 wells.

Thanks. And the Strawn potential you mentioned at 40%, where does that layout geographically either Counties or directions or is it concentrated or is it varied around a bit?

I'd say it's primarily in Midland Martin County and same with the Atoka, it's going to be midland and market.

When you look at the acreage map, it's essentially in the central part of our acreage holdings.

Brian Lively, Tudor, Pickering & Holt.

Just thinking about the vertical test that have in the Wolfcamp before going horizontal. What are the water cuts on those vertical wells?

The vertical on a typical Spraberry well?

Well, I just meant on the specific task. You said you got 5 to 10 barrels a day of uplift just testing the Wolfcamp before going into the horizontal program.

Yes. It's very little water, probably less than 1 to 1.

So it's not going to be like a typical full Spraberry completion where you see 60% to 70% water cut, you're expecting lower water cuts.

Yes. We're getting most of that water out of the upper Spraberry. The upper Spraberry seems to be a lot higher water saturation throughout the entire field, but it does hold lots of oil. That's what's pushing the water rate up into total in the typical Spraberry well.

So you said potentially 1 to 1, does that mean a 50% water cut? Is that what you're thinking?

One to one is 100%. So it's equal to 1 to 1.

You're saying oil equal to water is what you're saying?

Yes, exactly.

I just wanted to make sure I understood. Just on the Eagle Ford, and I'm sorry if I missed this, but what's your current backlog of uncompleted wells there?

Approximately 15.

15, and then you think you can work those down pretty fast now?

Yes. We're working them down as we speak. In fact, it was higher than that only a month ago. But the fact is we brought in these two frac fleets, one of which is a pioneer owned fleet and we are very effectively working down our frac bank as we speak. Should be no more than about 10 wells at the end of the year, for instance.

All right, thanks. Good color.

Eliecer Palacios, Maxim Group.

Just a quick question on your Alaska property. Can you provide us just a quick update on your potential exploration there and when can we hear results of your current well?

Yes. I did bring up already that our second Tool Rock well came on just in the last two days about 900 barrels a day. We'll be testing it over the next several weeks, and then we just finished a re-completion program on several wells, so we expect a up lift in our production. And then over the next -- we're preparing for again our winter program and we'll be drilling again several more Tool Rock wells. Going over the next two or three years we'll be drilling a key well on shore in the Tool Rock this coming winter. And in addition we'll be testing a deeper exploration zone that we've evaluated. But Tool Rock was the third zone, when we approved this project we only had two zones, the Nuiqsuit and the Kuparuk, we've added the Tool Rock now and we're looking at a fourth zone that's even deeper, we'll be testing this upcoming winter.

There are no further questions at this time.

Okay. We appreciate all the interest and during the quarter and look forward to talking to everybody on the next quarter down the road and hope everybody has a good summer coming up. Again, thanks.

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