先鋒自然資源 (PXD) 2012 Q2 法說會逐字稿

Welcome to Pioneer Natural Resources second 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, Senior Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the internet at www.pxd.com. Again, the internet site's access to slides related to today's call is www.pxd.com. At the website, select Investors, then select Investor Presentation.

This call is being recorded. A replay of the call will be archived on the internet site through August 22.

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 states and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page two of the slide presentation and in Pioneer's public findings made with the Securities and Exchange Commission.

At this time, for opening remarks, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

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

Scott's going to be up first; he will provide the financial and operating highlighting for the second quarter of 2012. He will then discuss the Company's plan to pursue a joint venture partner to accelerate the development of Pioneer's industry leading position in the horizontal Wolfcamp shale. He'll also update you on our increased production growth forecast for 2012 and capital spending plans over the remainder of the year.

After that, Tim will be up. He'll discuss our drilling results and plans for the horizontal Wolfcamp shale, Spraberry vertical wells, the Eagle Ford shale and the Barnett shale combo play. He will also update you on our activities in Alaska. Rich will then cover the second quarter financials in more detail and provide earnings guidance for the third quarter. And then after that, we will open up the call for your questions.

So, with that, I will turn the call over to Scott.

Thanks, Frank, and good morning.

On slide three on our highlights, we had a clean adjusted income number of $98 million, or $0.78 per adjusted share. Second quarter production, which we had already press released a couple of weeks ago, totaled over 150,000 barrels of oil equivalent per day. The Spraberry production was negatively impacted by about 4,800 barrels of oil equivalent per day due to unplanned third party NGL fractionation capacity shortfalls at Mont Belvieu.

It did include 2,800 barrels a day associated with NGL inventory build, which we do expect to sell between now and the end of the year and 2,000 barrels a day from ethane rejection that will continue. Production would have been about 155,000 barrels a day without the negative impact, which have been at the high end or above our guidance of 149,000 to 154,000 barrels a day.

We were up 4,000 barrels a day versus the first quarter. Primarily driven by the production growth in Spraberry, Eagle Ford, Barnett and Alaska.

One note is that oil production is up 70% over the last 12 months with Pioneer. Increasing 2012 production growth, our target range, which was 23% to 27% up to 25% to 29% as strong drilling and well performance is expected to outweigh the continued third party NGL fractionation capacity shortfalls in our reduced second-half drilling activity. We continue to advance the successful horizontal Wolfcamp shale plays.

We're announcing five additional wells, very successful, for a total of seven. The program is way exceeding expectations. Increasing our estimated ultimate recovery to 575,000 barrels of oil equivalent for 7,000-foot laterals in our southern acreage.

Also, we're announcing over the several months, we're pursuing a joint -- looking for a joint venture partner to accelerate horizontal Wolfcamp shale development in our southern 200,000 acres of our total prospective acreage position. We'll talk more about that in a minute.

Going to slide number four, continued on highlights, our deeper vertical drilling to the Strawn, Atoka, Mississippians continue to drive the strong Spraberry outperformance in that field. Also, what is important, maintaining our drilling capital at $2.4 billion by reducing second half activity in response to the recent -- in the last 60 days the price of WTI coming down from roughly $100 to between $85 to $90 from lower commodity prices.

We're taking the Spraberry rig count down a little bit quicker than we anticipated in this price environment from 40 to 30, reducing the Barnett rig count from two to one. Also, we're looking at reducing the Spraberry vertical rig count from one to three rigs.

In addition, we have terminated some third party fracture stimulation fleets that are predominantly using Pioneer fracture stimulation fleets, saving lots of capital there.

We liquidated some gas derivatives in 2014 and 2015 several weeks ago. The market obviously has moved up since then substantially with cash proceeds of about $143 million. And also recently when oil peaked at about $93 just recently, we went ahead and added 8,000 barrels a day of oil swaps for the next -- for the last five months of 2012, which puts us close to 100% of our oil hedge for the rest of this year.

We completed a successful 10-year senior note offering of $600 million at 3.95%. And with the S&P upgrade, we've recently been upgraded by Moody's.

The Wolfcamp shale joint venture opportunity on slide number five. With the data room opening up in September, we're offering 33% to 50% of Pioneer's working interest in approximately 200,000 acres in the southern portion of the Midland Basin, which is about 8% to 12% of our total acreage position. When you look at a partner obtaining either a 33% or a 50% of our 200,000 acres, it's going to include all Wolfcamp intervals, A, B, C and D.

There is 4,000 potential horizontal development locations, excluding down spacing potential. Our 4,000 locations, we're drilling now on 140-acre spacing and as you can see with activity like in Eagle Ford oil where people are taking that play down to a 53-acre spacing. So, it's huge potential over and above the 4,000 and over and above the 2 billion-barrel gross resource potential.

The 2 billion barrels are just associated with the 4,000 locations. Oil content greater than 70% with liquids greater than 90%. Estimated ultimate recovery in this acreage, about 575,000 barrels of oil equivalent for a 7,000-foot lateral in the current environment of $85 oil flat and $4 gas flat, $7 million well cost delivers a 45% before tax IRR.

The primary purpose of the shale JV opportunity is to accelerate development, enhances our net asset value and project returns, allows us to de-risk the play with somebody else's capital. And also allows us to shift capital to Midland Martin and our counties to the north to prove up additional Wolfcamp, where we will own essentially about 100%.

Going to slide six, increasing our 2012 production growth target. Again, as I had mentioned before, we're going from 23% to 27% up to 25% to 29%. Obviously, our strong drilling in all of our key areas is outweighing what's happened on the NGL fractionation at Mont Belvieu.

Again, going into future years beyond 2012, we'll wait until early 2013 to come out that guidance. But again, that is fairly dependent upon commodity prices and service costs going forward.

Capital spending for the second half of the year in cash flow on slide number seven, as I mentioned earlier, we kept our drilling capital at $2.4 billion by reducing certain areas and activity. The vertical integration of $500 million. We did add about $100 million for expanding field facilities, primarily in the Permian Basin, Eagle Ford that will carry us for several years with our accelerated activity over the next several years in those two key areas, for a total of $2.9 billion, funded from operating cash flow, equity proceeds, liquid derivatives and inventory, pipe inventory reduction, South Africa divesture and south Texas acreage sale.

Going to slide number eight, again, another slide to emphasize the fact that the first half capital spending was weighted toward the first half, due to a second rig drilling in Alaska, which drilled two exploration wells, which we owned 100% of each of those wells, running 40 Spraberry rigs in the first half, going to 30 in the second half. We did accelerate our frac bank reduction of 40 wells, so a lot more completion costs in the first half.

A lot of capital. We're spending about $2 million extra for science in the first half on horizontal Wolfcamp wells and then seismic acquisition primary in the Permian. Going into the second half, we'll be running somewhere between 27 and 30 Spraberry vertical rigs, 4 horizontal rigs until the very end of the year where we'll be adding three more rigs ourselves, regardless of what happens on the joint venture.

If the joint venture does go through, obviously, we'll be running more rigs going into 2013 and 2014. 12 Eagle Ford rigs, one Barnett shale combo rig, one Alaska rig and again, predominantly using our own frac fleets the second half of the year.

And finally on slide number nine, South Africa should be closing in the next couple of weeks. We're predominantly a US-asset-based Company. We have increased our resource potential up to 7 billion barrels of oil equivalent. We think there is additional upside from this number. This is increased primarily with the southern Wolfcamp acreage play.

As we move into Midland and Martin County, we think there is tremendous upsize to the number as we expand the Wolfcamp play up north. Again, we got four great core areas. The joint venture is going to obviously accelerate the development of the Wolfcamp shale play. Vertical integration substantially improves returns. We have a great derivative position that protects margins over the next two years and a strong investment grade financial position.

Let me stop there and turn it over to Tim to go more into the Wolfcamp.

Thanks, Scott. We're pleased to finally be able to report our drilling results from the early campaign in the southern 200,000 acres that Scott was referring to in the horizontal Wolfcamp shale play. In summary, the early results from the program are exceeding our expectations.

But first, let me do this. Let me update on you the Giddings wells in Upton County. Those are the first two horizontal wells drilled several months ago to the north. And as shown on the slide, we have had phenomenal results from these wells, the first of which has made 107,000 BOE in about 9.5 months, the second of which making 83,000 BOE in seven months.

Again, this is roughly about seven times the amount of volume that a typical 140,000-barrel type curve from vertical wells would make. And I will refresh your memory that these wells actually naturally flowed up tubing until only about 1.5 months ago. Now, only in the 1.5 months have we put the wells on artificial lift.

You will see in the box to the right that we have a conservative 650,000 BOE EUR for these wells, realizing that their stimulated lateral lengths were only 5,300 feet. As we increase the length of those laterals, you will see the EUR to the north grow considerably. The important thing about the wells is they are still exceeding expectations. Even in terms of current production, they're averaging about 365 BOE per day which is, again, a phenomenal result for these first two wells and is indicative of what we expect as we go north onto our acreage.

Now, let's turn to the south. We, as Scott mentioned, placed five B interval wells on production during the quarter. Mostly they're in southern Upton and Reagan Counties as the map shows. And the actual data for these wells, all five of them in detail, are shown in the table below.

Importantly, the wells have done exceptionally well, 300 BOE to 600 BOE per day in terms of peak 30-day IP rates. Of course, we think the 30-day peak rate is really more indicative of performance than a 24-hour rate. And importantly, a lot of these wells are really doing phenomenally in terms of showing relatively stabilized production. In fact, of the total of the five wells, on average, they're still producing over 300 barrels a day over the last seven days.

So, it goes to show the wells are holding up beautifully. And the last of the wells is shown on the table, University 10-13 is still today naturally flowing upcasing and showing excellent rates, as shown on the table. We're actually considering completing all of the wells, perhaps in the future in this fashion, so as to be able to move fluids faster.

And as can you see, we're continuing to really refine the optimal completion techniques on these wells, and I think you will see improvement as we go forward based on all of the technology we're applying.

Importantly, as we move ahead, I think the production rates and EURs will also increase in relation to the increase in stimulated lateral lengths. The numbers we quote today on EURs are based on 7,000-foot laterals where we will be looking at drilling some 9,000-foot laterals in the second half of the year.

As Scott mentioned, just based on 7,000-foot laterals, we have increased the EURs in the southern area to about 575,000 BOE. You will recall our range prior to having this data was more in the range of 350,000 BOE to 500,000 BOE. So, the results look very, very good in the early stages of our drilling campaign.

Turning now to slide 11, this slide is focusing on the future activity in the horizontal Wolfcamp shale play the rest of the year and into next year. Of course, our activity as shown in the map in the oval there is related to trying to hold the 50,000-acres that would otherwise expire at the end of 2013. And toward that end, we have to drill about 90 wells or so between 2012 and 2013 to hold the acreage.

Today, we have four rigs running, we'll be increasing that to seven rigs in the late part of the year. Those rigs are all contracted today. There are nine wells which have been drilled that are waiting completion, they are waiting on fracs and importantly, two of those wells, our first Wolfcamp A test, in fact the first frac -- the first well being fracked began on Monday, the second will be done in mid-month. Accordingly, by the time the next call occurs, we should have a lot of interesting data on Wolfcamp A as well.

The important note regarding drilling costs is that we are trying to move to more of a development drilling campaign. Of course, we have been spending a lot of money on the early wells for science and data, but we're drilling our first two development wells focusing on trying to get the well costs in that range of about $7 million, and I think we can do that.

One of the changes that we're in the process of implementing is increasing utilization of our Brady Brown sand from Premier Silica, that's our sand company. Today, we pump about 50% white sand, 50% resin-coated sand. Our goal as we move forward is to move to about 85% Brady Brown sand, and that can save us $1 million per well. So, this is an important thing to be testing immediately, and that is exactly what we're doing.

As Scott had mentioned earlier, we also will be marching forward and delineating the northern acres, drilling some wells in Midland and Martin and Gaines counties as we get into the latter part of the year. We anticipate higher oil in place there, deeper drilling, higher pressures and we think as a result, more productivity going north. Of course, that will help us be able to establish the prospectivity of our acreage in terms of the total acreage package.

Recently, our team of Permian engineers did a great job in working with the Railroad Commission of Texas to adopt new field rules. The objective is to optimally develop the vertical and horizontal Spraberry sections. Ultimately, this would allow a development which would feature up to, perhaps more even than 14 horizontal wells in the Wolfcamp on 1.5 sections, which could be coupled with as many as 41 offsetting 20-acre space verticals.

You're looking at fuel rule change that will really significantly improve the recoveries and we believe will optimally develop the field. As you can see, we're just in the beginning and unlocking the immense value of the horizontal Wolfcamp acreage and our prospective acreage in the play. So stay tuned as we start the process of completing the rest of these wells and drill further wells.

On slide 12, I'm now turning to the vertical deepening program. As well as the horizontal Wolfcamp shale program is going, it's still the vertical drilling program, specifically the deepening of wells which has allowed us to exceed our growth targets through the first half of this year. In fact, at this point, we're deepening about 65% of the vertical program we had planned this year to be deepening only about 50%. But as good as the results have been, we're increasing the program to about two-thirds of our campaign.

The table here on slide 12 shows 24-hour IP rates or the deepened wells, whether it be the Strawn, the Atoka or the Mississippian. You can see these compare very favorably when you consider that the 140,000-barrel type curve associated with normal vertical Wolfcamp completed wells has an IP of about 90,000 BOE per day. You can see the impact which the deepening is having in the early stages of well performance. The table also shows the potential incremental EUR from the deepenings.

Importantly, we have done some work, some further analysis and refining of our mapping to assess the prospectivity from the deeper zones. We now believe the Strawn prospectivity is toward the top end of our prior range. We had used 60% to 70%, we now believe it's about 70% of the acreage.

Atoka is coming in at the top end of its previous range of 25% to 50%. We now believe it's in the neighborhood of 40% to 50% and Mississippian continues to be prospective for about 20% of the acreage. The deepening really has been an excellent result for us so far, it's the thing that is leading us to outperform in this play. It's the case that we can, I think, add significant EUR, perhaps even up to 100,000 BOE per well when these deep zones are commingled.

Turning to slide 13, this really is a slide which shows the effect of the successful drilling campaign and the effect of the well deepenings I just covered. You can see we came in at 64,000 BOE a day for the quarter. That would have been 68,500 BOE a day for the quarter other than for the well-documented NGL issues that Scott has already covered.

That has led us to increase the forecast for this year's production for the Spraberry trend area to 63,000 to 67,000 BOE per day. And that underpins the increase in the overall corporate production guidance that Scott has already covered. We really anticipate that although we're going to be in a situation in which we have ethane rejection through the rest of this year, we think it will be a very strong finish to the year. This Permian asset base is delivering in a major way, and a lot of the production, of course, is due to the well deepenings.

Now turning to the Eagle Ford on slide 14, this is an asset to base that continues to grow and will continue to do so. We put 37 wells on production during the quarter, we continue to have 12 rigs running and still anticipate a 125-well campaign. We have reduced slightly the number of dry gas wells that we plan to drill from about 15% of the program, now it looks like we'll only drill about 10% of the program, or about 12 wells focused on holding dry gas acreage in response to commodity prices.

We continue to expand the limits of the utilization of white sand. Of course, we were using white sand in several wells already this year. 53 wells have been stimulated using white sand. Importantly, we're just using white sand for the first time on some dry gas drilling in order to try to cut the cost on dry gas wells, and we have four more of those wells planned for the remainder of this year. Importantly, that is a $700,000 savings per well, and that is why it's important to test it on what would otherwise be economically challenged dry gas wells.

We're a league leader when it comes to having infrastructure in place. We have added three more CGPs in the second quarter, that gives us 11. We have three more to put in next year, and that will have us substantially complete in terms of our infrastructure build out at the end of 2013 for the Eagle Ford shale play.

Turning to slide 15, this shows the result of the activity and the growth from the Eagle Ford shale. We expect that growth to increase in the second half of the year, and you can see that in the overall fiscal year -- our full-year guidance. We're going to be putting more wells on production in the second half than we did in the first. We popped 63 wells in the first half of this year and anticipate putting 76 wells on production in the second half of the year, and that underpins the production increase in the second half of the year.

Turning to slide 16, our third major area of Texas-based drillings is in the Barnett shale combo play. We drilled 12 wells in the second quarter. We did announce, as Scott mentioned, reducing our rig count by one, from two rigs to one rig. This is in response to a combination of relatively low natural gas prices as well as the decline in NGL prices that was pretty substantial in the second quarter.

We have seen some drilling results that have been very encouraging. In fact, they have been oily well results which, of course, is beneficial in today's commodity price environment. In fact, we drilled seven recent wells that had 30-day peak rates of 345 BOE per day and were more oily than the typical Barnett shale well.

Importantly, we are still incrementally adding value by gaining substantial efficiencies in drilling. We moved our drilling times on these Barnett shale wells down from about 16 days last year to about 10 days currently, and that savings is significant.

In turn, as you turn to slide 17, production continues to grow in the Barnett shale combo play. We're confident in the range for the year. Of course, the rate of growth will slow as we get towards the end of the year as we see the effects of reducing the rig count from two down to one.

We'll be looking at and evaluating the 2013 capital for the Barnett shale combo play in the later part of this year as we look at the outlook for NGL prices as well as natural gas prices through the rest of this year and looking at the expectations for next year.

Slide 18, a quick update on Alaska. Production was up in the quarter owing to the first successful Nuiqsut well that had been mechanically diverted frac earlier this year, and that well was on for most of the quarter. We do have the one rig running still on the island, and that rig is principally working on drilling wells that will be the subject of four additional diverted fracs for the next upcoming winter season.

Of course, those fracs will not be done until well after the freeze. We need space for the frac lead and we need space for frac tanks and other equipment, so we really need ice for space around the island. We really won't be getting to those fracs until probably February.

In addition, we are doing some planning to drill perhaps another Torok appraisal well from the shore. The idea is offsetting the excellent well we drilled last winter and evaluating the potential for development and in fact, spending money on the upfront feed study as we speak. We believe as a result of the campaign last year, we have added about 50 million barrels of oil in terms of resource potential in the Torok area.

Our other principally gas-producing areas in the mid-continent and Raton and south Texas performed very well in the quarter, despite being allocated very little capital. And the slow decline on these assets gives us a great production foundation from which we can grow, and that is a tribute to the people in these divisions doing an excellent job.

With that, I am going to pass it over to Rich for a review of the second quarter financials and his outlook for next quarter.

Thanks, Tim.

I'm going to start on slide 19. For the quarter, the Company reported a net loss attributable to common stockholders of $70 million, or $0.57 per diluted share. That did include unrealized mark-to-market derivative gains of $61 million, or $0.49 per diluted share and unusual items representing net charges of $229 million, or $1.84.

Adjusting for those items, most of which was non-cash related to Barnett shale impairment related to legacy dry gas properties resulted in a $98 million, as Scott mentioned, of adjusted income, or $0.78 per diluted share.

Looking at the bottom of slide 19, production. Scott and Tim have both discussed, so I am not going to talk anymore about that. If you look at the other items irrelative to our second quarter guidance, they were either within guidance or on the positive side of guidance. Another good quarter for the Company.

Turning to slide 20 and looking at price realizations, as Scott mentioned, we did put out middle of July, our production and price realizations for the quarter. Here, as you can see, looking at oil, realized prices were down 12% from the first quarter at $86.87. NGL prices were impacted pretty substantially due to the lower ethane and propane prices, and they were down 22% from the first quarter at $32.62 per barrel. And then looking at gas, we were down 20% to $2, from $2.51 in the first quarter.

Turning to slide 21, production costs. Production costs came in for the quarter at $14.70 per BOE, that was a 7% increase from the first quarter. A couple of items that are enumerated here, increased workover activity during the quarter.

Just the timing of when that activity took place. We have seen some minimal cost inflation on labor and saltwater disposal costs that hit us in the second quarter as well. And then, it's small there at the bottom of the bar, but net gas processing margins were down.

We processed third party gas through our facilities where we have excess capacity, and we get paid generally for that with percentage of proceeds and with lower gas and NGL prices that affected our margins. And then lastly, when you look at production costs on a BOE basis, the ethane rejection reduced our production or the denominator and the calculation, and so that impacted production cost by $0.19 per BOE for the quarter.

Turning to slide 22, third quarter guidance. Production guidance of 155,000 to 159,000 BOEs per day for the third quarter, that does reflect continued ethane rejections throughout the quarter. Our production costs at $13.50 to $15.50 per BOE. Exploration abandonment is $25 million to $40 million, and that is down slightly with just less exploration drilling activity and seismic activity in the second half.

The other items are consistent with previous guidance, other than interest expense reflects the bond offering that Scott talked about earlier, and then other expense reflects additional rig termination fees.

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

Thank you. (Operator Instructions) We'll go first to first to Brian Lively with Tudor Pickering Holt.

Hi, Good morning.

Good morning, Brian.

On the five Wolfcamp wells, it's just interesting that the University wells are all completed in close proximity, but the IPs were different. I understand there is some variability to be expected, but when you guys look geologically, is there really any difference in terms of the lithology or the rock as you look across that southern acreage position where you've drilled?

No. We really don't see too much. There is a combination, I think that Tim mentioned it, that you have got one well on jet pump, several on gas lift, and we're learning that flowing back the wells up the casing is probably the best process going forward. That is why you get different variance of rates. We're going -- almost all of our wells now, we're going to start flowing back for several weeks to months to get the -- establish the low decline and get the best performance.

So, we just don't see much changes. We think as you move maybe toward our Rocker B, you may get a little bit more gas. But so far, our gas/oil ratios are staying 1,000 or under and even as we move south. Now, as we move southeast, more towards EOG and [approach], we would anticipate maybe a little bit more gas than NGLs. We don't know that yet.

And on the University wells, I guess the 450-ish IP wells that were put on artificial lift early, I think, Scott, you're saying that you might not do that in the future, and that could be the reason why the wells are lower rate than, say, some of the other offsets that are on natural flow?

Yes, that's right. In fact, the best University well, we just --- it's been flowing back, and Tim mentioned it. It's the process that we used in Giddings also, and that is why it has got a higher 30-day rate because we're flowing it back. The goal is to flow it back up 5.5 inch casing versus -- Giddings wells are actually flowed back. They were restricted, they were flowing back under tubing. So, we just think the flowback is the best procedure right now, and we're going to do that going forward for a while.

I guess that supports the idea that you'll see flatter declines on some of the wells, especially ones you put artificial lift on early?

Yes.

And then just on that, the overall acreage. Is there any way that you guys could segment it, maybe between the three different areas, the southern, the mid and then the northern that you have untested and give some sense of what you guys think you have derisked at this point?

To the north, as you recall, the only well we've drilled to the north has been a Cline well in the D zone in Midland County. In fact, that well has become very flat and it's getting better and better. We only fracked -- it was only that well at a 3,800-foot lateral.

We're becoming, obviously, more optimistic in the Cline through Midland and Martin County, but we're still going to be focusing on the A and the B zone. But with the 70,000 -- a database of 70,000 logs and core data, our maps show that in some of the other activity to the north, Devon's had a pretty good well in Ector County just opposite due west of Midland County. Then you got all of the activity in Glasscock County, has given our confidence that Midland and Martin are going to be as good or better than Upton and Reagan.

That's fantastic. And then the last question from me is just looking at the Devon JV that was announced this morning, which was effectively $70 to $100 or so an acre. As you guys compare the results on that eastern edge of the play versus where your wells and where you are looking to JV in the southern Wolfcamp area, would your expectations be at least that much from a per-acre type math analysis?

Their acreage -- first of all, their acreage is more exploratory in general. They have some of it on the eastern -- where there has been some pretty good Cline wells, but a lot of it moves east -- further east into the eastern shelf. They probably are more limited to potentially one zone where we have potential for up to four to five laterals in each of our -- you got one in the A, you may have up to two in the B because it's about 500-feet thick. You will have some in the C and then you'll have some in the D or the Cline.

So, our acreage, I think it is obviously a lot more proven, has a lot more upside, so obviously should demand a much, much higher price.

Great. I will leave it there. Thanks a lot, Scott.

Next, we'll hear from Cameron Horwitz with US Capital Advisors.

Hey, guys, good morning. With this 575 MBOE EUR that you've put out here on the Wolfcamp, are you signaling that the five wells that you released here are 575 MBOE EURs, or is that an average of the Giddings wells and these wells, or how should we think about that?

Cameron, the way you should look at it is this. The 575,000 BOE type curve or EUR is reflective of 7,000-foot laterals. If you take a look at these wells in the table on slide 10, you will notice they're anywhere between 5,700-feet and 6,400 -- 6,500 stimulated lateral length. These will be slightly less than 575 when we equilibrate or adjust the wells as if they were 7,000-foot laterals, you get 575. These would just simply be an average would be slightly lower than that, based on their lateral length.

Okay. Okay, that is helpful. And just in terms of the JV, have you guys already started discussions there, or what is the time table that we can expect?

I said earlier that the data room will open in September, and bids will be due by the end of the year. And then closing sometime in the first quarter.

Okay, excellent. Thanks, a lot, I appreciate the color.

Next we'll go to Will Green with Stephens.

Good morning, guys.

Will.

I appreciate the additional color on the Wolfcamp. Maybe you guys could help us on what you expect on a 30-day rate, what you expect on a first year decline for that 575 MBOE type curve?

Yes, I think it's best, at some point in time, we're getting ready to bring on several more wells. We will actually come out as we move more toward the flowback procedure versus gas lift or jet pump. We'll be coming out with a type curve to give you that data.

Okay. Great. I will look for that. And then you noted that you guys are going to be targeting the Wolfcamp A pretty soon. What is the timetable on going into the C bench?

Right now, we're focused on, besides the A and the B, we're going to focusing on the lower B. We think it's going to take two wells into the B, based on its thickness. And then eventually, we'll be moving in the C and also the Cline.

Like I said, in some areas in that southern acreage, you could have five horizontals in regard to that area. But what we call the lower B will be next after the A and then moving into the C and the D over the next few months.

All right. Great. That's all I had. Thanks, guys.

Next, we'll go to Leo Mariani with RBC Capital Markets.

Hey, guys. Just wanted to ask a question here on the potential JV. Just wanted to see if anything has changed philosophically in you all's minds. I know for awhile you guys have said that a JV is likely off the table. You guys are saying that your southern Wolfcamp acreage is going be held by year end '13. It looks like, clearly, you've got the funding at this point to drill it up, fold it yourself. I know you talked about any V acceleration as a result of JV, but has anything else kind of philosophically changed to want to cause you guys to JV this as opposed to your thinking seemed earlier not to want to do that?

When asked the question, Leo, over the last year, we have always been open about a potential JV as a source of funds. And we're getting more confident that this entire Wolfcamp play and our entire position could be very profitable. And the primary reason of the JV is that it allows us to accelerate the development of that 200,000 acres and have somebody else cover our capital for the next three or four years.

At the end of three or four years, we have enough cash flow to develop that. In fact, in this opportunity, the rig count gets up to about 20 rigs. Just the 200,000 acres gets over 200,000 barrels a day equivalent. It's a $25 billion investment for a total of us and a joint venture partner over the next several years. Tremendous growth.

It allows us to accelerate that and shift capital to the north where we own 100% in Midland, Martin and Gaines Counties, that is the primary driver. And we're in a little bit lower oil price environment, too.

Okay, got you. Question on the EURs in the southern Wolfcamp. You talked about the 575,000. I know you all said you would come out with your type curve next quarter. It looks like you got five new wells, a little bit more than 30 days of the production history. It feels a little bit early to come out with the big increase on the five wells. What else are you looking at other than those five wells to get to the 575,000 EUR?

Yes, there is a total of over -- you got 40 rigs running, there's a total of 400 wells producing, so there is lots of data. We got 70,000 logs, lots of core data, so we got the comp. There's a lot of other operators that are drilling around us. We just feel like we had the confidence of those other oil shales like the Eagle Ford oil shale. We're using -- also using the -- there's a good three years of results there in the oil shale opportunity. It's a combination of all of those factors.

Okay. Got you. And in terms of your slide deck, obviously, you have a lot of info in there. I think you made a comment in the slides that your 2013 to 2014 production guidance is kind of wait and see at this point. Is that purely just a function of what commodity prices might do in the next couple of years?

Yes, we said commodity prices and service costs. It's a question whether or not we use a $80 price deck, a $85 price deck or a $90 or $100. It really depends on -- and that is more dependent upon less in the oil and gas industry, but what happens in Europe and the rest of the world.

So, we have to come up with a long-term price case, and then we'll come out. On almost all those cases, we're going to have double-digit growth for several years, 5 to 10 years. It's just a question of how high we can push the growth number, which is very dependent upon the price of oil.

Got you, okay. And last question on just capital costs, you kept your drilling budget at $2.4 billion, reducing activity a little bit. Can you just give us a little bit of color around where you might have seen a little cost creep to maintain that $2.4 billion on the slightly lower activity?

We've seen some creep, Leo, in a couple of areas, and they've actually been well documented, one is guar where we have been subject at least to some cost increases, really throughout this year. And it probably led to about, I don't know, $25 million run rate annual increase in guar costs that we have seen over the last couple of quarters.

The other thing that comes to mind is of course in the Midland Basin when you have -- and actually, the whole Permian basin, you had 540 rigs running. The number of people required to get that done is incredible and as a result, labor costs have gone up probably about 10% this year.

I would say those are by far and away the biggest issues when it comes to inflation. The rest of the costs have been generally pretty flat this year.

All right, thanks a lot, guys.

The other thing I would just say, just to make it clear is we have done scope changes in some of our areas. As you know, we're deepening the wells in the Permian Basin, the vertical wells, and we're actually increasing lateral lengths in some areas compared to the original plan. So, some of it is scope as well, not just inflation.

All right, makes sense, thanks.

Next we'll hear from Dave Kistler with Simmons & Company.

Real quickly, just one more the JV. In terms of the structure of it, how do you guys think about it from a cash versus carry perspective? Do you have a preference for how you receive capital associated with that JV?

Yes. It will be very -- we anticipate it will be very similar to the Reliance structure.

Okay. That is helpful. And then switching over to NGLs and NGL realizations. As we look at the hedges you guys put in place for 3Q and 4Q at over $60 a barrel of oil equivalent versus the current market that seems like it's in kind of a $30 range, can you talk about how you were able to secure those or if that is relative to just a certain portion of the NGL chain? Maybe the higher portion, C5, et cetera.

Yes, those volumes that we added were mainly on the heavier part of the stream, and so that is why you see the higher realized prices. And then we also had some propane ones that were tied to WTI. It's really a combination of the heavier stream and then propane that we did a while back and then tied it to WTI, so we're getting a higher realization.

Okay, and then --.

-- percent of WTI.

Okay, that is helpful. And then when you talk about the NGL inventory that you compiled, again, is that segmented to a certain part of the NGL chain? I would imagine probably the higher portion of the chain?

Those are just Permian NGL barrels, so they end up being about 35% ethane and probably about 20% propane and 20% butanes and about 20% natural gasoline. It's sort of a typical Permian Basin NGL barrel.

Okay, that is helpful. Last one, looking at your decision to monetize your hedges on gas in '14 and a portion of them in '15. Was that more opportunistic as far as aggregating capital, or are you in some respects also maybe calling a bottom on where you see natural gas prices in '14 and '15?

It's a combination of both. Opportunistic and at the same time reserving or maintaining our strong balance sheet.

Okay. Appreciate it, guys. Thank you for the color.

Next, we'll go to Brian Singer with Goldman Sachs.

Thanks, good morning.

Brian.

When you talk about accelerating drilling on the back of the JV in the Wolfcamp, can you talk to what kind of acceleration that could be? And you may have mentioned in response to an earlier question 20 rigs in the southern acreage, but where do you see your horizontal rig count going in south plus north with a successful JV?

Yes, I mentioned, Brian, that over time we do have the opportunity to get up to 20 horizontal rigs. It's spending within cash flow over the next several years. The number of rigs that we moved to the north we haven't determined yet. Right now it's just one rig. Depending on the results in Midland and Martin County, which is really going to be tied for service costs and commodity prices going into the next two or three years will be determining factor.

In addition, it's important that we live within cash flow as a company. That would be the primary determining factor in the out years to how much we devote to those northern counties where we own 100%.

And you don't need the 20 rigs there to hold acreage. So, from an acceleration perspective, would -- based on your quite bullish comments on northern potential, would you not ultimately want a higher rig count in the north than you would in the south?

Yes, a lot of it depends on infrastructure, our ability to -- our people too. But I said the determining factor, the joint venture is designed in the rig count is to live within cash flow from our standpoint.

So, the 20 rigs allows growth -- significant growth for several years. We'll be running those 20 rigs, and the determining factor after that going up north is our results living within cash flow as a company and what the commodity prices are. So, it's a combination of all three. I can't really predict how many rigs we're going to be running in Midland and Martin County on the horizontal at this point of time.

Okay, and then at the time you issued equity last year and accelerated spending in the Wolfcamp shale southern region to hold your acreage, you'd indicated there were multiple other levers that you could pull asset sale wise, some of which you've done. South Africa selling this JV. You'd also mentioned selling Alaska, potentially dropping down assets to the MLP.

Can you talk to about where you stand on some of these other remaining levers? And should a successful JV put to rest any chance of equity issuance through the end of 2013?

Yes, first of all, the JV is one of the cheapest costs of capital. It's obviously another reason why we're pursuing that. But in addition, we look at all of our assets are for sale for the right price. We will continue to look at the performance of those assets and make the determination in the future of whether or not we should be selling an asset or not.

Yes, you asked about equity. We have no plans at all to be issuing equity. Obviously, with the opportunity to do the joint venture by far exceeds the best way to drive the performance and bring forward the opportunities in the southern acreage versus issuing equity. We're very surprised by the comments that our IR department has heard about us issuing equity, the last thing we're going to do is issue equity. We just issued it last December, we do not want to be considered, like some people are, continued issuers in common equity.

Thanks a lot.

Going next to Brian Corales with Howard Weil.

Good morning, guys. Looking forward, do you expect -- should we think about even lower vertical rigs, say 2013, '14, as the increased horizontal rigs in the Permian continue?

That is always a possibility. If we get the type of returns like we have in Giddings, and as we move into the north acreage, then the returns from the horizontal Wolfcamp will probably most likely exceed the vertical. We'll just have to determine at that point in time, is it better to run more horizontal rigs and less verticals, or a combination of both?

It's just something we'll just have to wait and see. That is probably a decision a good year from now.

And as you get up north, say into Midland and Martin, Glasscock counties, is there any concern that you will have from previously vertically drilled wells, or none of them really reach the Wolfcamp or minimal reach the Wolfcamp. How should we think any about that?

I think the important message is that the -- from a vertical well, when we frac the Wolfcamp, it drains around three to four acres. So, it essentially has no effect on us putting a horizontal well or a series of horizontal wells into the Wolfcamp. The fact that it's so tight and we're just not exposing much of the drainage area with a vertical well.

Okay, and just one more general question. In the Wolfcamp, how much thicker is the entire Wolfcamp section in the heart of the Spraberry trend like in Midland County versus the southern acreage?

Throughout our entire acreage position, it runs from 1,500-feet to 2,600-feet. So, it does vary in thickness.

Okay, okay. All right. Thanks, guys.

You're welcome.

Going next to Mario Barraza with Tuohy Brothers.

Hey, good morning, guys. The majority of my questions have been answered, but are you guys still thinking in the northern portion of your acreage it's still roughly 200,000 net acres prospective for the horizontal Wolfcamp, or has that grown at all?

Tim mentioned that we're going to be drilling wells in the Midland, Martin and Gaines, so that will be our entire position, somewhere between 800,000 and 900,000 acres.

Okay. And then also with the JV, if you guys are able to coin and close that in the first quarter next year, I know in a couple of your recent presentations, you have laid out your midstream plans. Do you have the midstream lined up to support such a -- the ramp up you could be targeting with the JV on the production side?

Yes, Mario. Of course, we're planning ahead in terms of this increased ramp up in drilling and activity, and we have participated in some firm transportation deals on oil pipelines to make sure we can move the volume associated with that drilling. Most of those projects come on in 2013, about the same time that we would anticipate having the beginning points of increased production, and so that is in good hands, I think.

We have got expansion space on our NGL offtake that comes in place in early 2013. We're also expanding our own Midkiff/Benedum gas plants from 260 million cubic feet a day to 460 million cubic feet a day by the end of next year. And the sum total of all of those, we think will, the best we can, avoid any kind of short-term bottlenecks. Of course, we're still seeing a bottleneck in Mont Belvieu pertaining to the NGLs and ethane rejection we mentioned. But we anticipate that will be likely done and really not an issue after the end of this year.

Okay. That is all I had right now. Thanks.

Our next question will come from Charles Meade with Johnson Rice.

Morning, gentlemen. Thank you for taking my question. Going back to your guide-up for 2012, it looks like that is really being driven by the Spraberry volumes. I'm curious, is that going to make the kind of the incremental volumes in that guide-up more oily than the overall mix?

I think so. As you know, Charles, when we drill those Spraberry wells they are vertical wells, particularly in the early part of their life, they're making 80% plus crude oil. That's higher than our current production mix and so by definition, it will increase our oil mix.

Got it.

-- second half of the year.

And then following up on that for the missing volumes that you guys are going to have with ethane rejection, is that going to -- you would also expect that to increase your gas realizations per MCF, is that something that we should expect going forward?

Really, if you take a look at it, it's a relatively small impact is the answer.

Okay. Got it. And then two other quick ones for me. First, Tim, when you mentioned that those XBC Giddings Estate wells are still exceeding expectations, is that -- you are referring to that new 650 EUR expectation?

Well, I'm really referring to the fact that the results of the wells from a production standpoint have been phenomenal and seven times that of a typical 140,000 barrel vertical well. And they exhibited tremendously flat production, compared to what you would expect. And as I mentioned in the call, in my slide, they're producing on average, 365 BOE per day still, which is unheard of, I guess, in the Permian Basin in recent history.

The EURs of those wells at 650,000 BOE estimate, really is more reflective of the fact they have only 5,300-foot stimulated lateral sections. You can, I think, pretty much prorate up by virtue of a 7,000-foot lateral or higher the EUR impact of that in the same area would be substantially higher than 650.

Got it, got it. And then the last question, how -- there has been a lot of talk about the -- some of the cost inflation on the service side, but this is more of an impression or a judgment call on your part. How much do you think that your drilling efficiencies have offset that cost inflation in terms of overall efficiency of your CapEx budget?

We're seeing, as I mentioned also earlier, seeing pretty dramatic increases in efficiencies of drilling in combination of Barnett shale. Permian Basin, of course, we were experiencing having a lot of rigs running. We're just flat line in terms of already having driven out most of the cost. We're definitely improving in the Eagle Ford shale in terms of time and cost on wells.

The one thing to note is our vertical integration is saving a tremendous amount of money right now. The combination of the Pioneer pumping services and our well services. In fact, they are saving capital at a basis of second quarter run rate of over $270 million a year, so that is really where we're getting the cost advantage is the fact the vertical integration is paying off handsomely.

Got it, so it sounds like that is the bigger of the two components. I appreciate your color on that, Tim.

Sure.

Our next question will come from Sven Del Pozzo with IHS Herold.

Good morning. I believe Tim mentioned something about field rules. I think he said 14 horizontals per section. Am I right? Did I hear that correctly?

I think we could drill a minimum of 14. 14 would be in contemplation of drilling an A and a B bench well in a section and a half that we'd be able to drill a total of 14 of those. But to the extent we were to drill C or D bench wells, we could actually increase that.

Of course, this is 960-acres, so the total well count would be limited to 48 wells, based on 20-acre spacing. But we could drill a substantial number of more horizontal wells based on the fact as long as they're in map view relatively close to each other, they only count as one location.

So, it is plausible you could you drill, for instance, 28 horizontal wells and still drill 41 vertical wells in a section and a half. This field rule change gives us a lot of latitude in terms of being able to optimally develop this field, considering you could be looking at numerous stacked laterals and then you can offset those with either existing or offset 20s. You're looking at a substantial amount of capital to develop what would only be a section and a half in those scenarios.

Okay, so you would probably be more inclined after you hold your acreage to develop more densely, I guess, drill more wells for a given service area because there is probably sweet spots that you're going to discover.

I think that is very plausible, probably will not occur until 2014 when we finish the acreage gather. You want to call it that. But, it's something we're contemplating now.

Okay. I think it was slide --- yes slide 12 with the vertical Spraberry type curves, and the average 24-hour IP rates shown there.

What should we think about in terms of dewatering times associated with these wells for the frac water to come back and also any formation water when we are doing our modeling? Or are we just supposed to say, okay, day one, 24-hour IP rate and plug in your number?

These wells pretty much come on production when we turn on the pump and basically, of course, you're producing a large amount of water with that. But in the Spraberry trend area, these vertical wells, we're producing water through the life of the well. It's different in the Wolfcamp where there is not a lot of water in situ. In this case, the Spraberry trend area, we're producing 250,000 barrels of water every day from these vertical wells. So, it's not exactly the same case as when you're thinking about horizontal as compared to vertical.

Okay, and then the verticals, how about for the Strawn, Atoka, and Mississippian? Would you characterize the formation water in those formations similar to what you said about the Spraberry trend or more like the Wolfcamp where there's not as much?

Much more like the Spraberry trend area.

Okay, and then just to quantify, how many Spraberry vertical wells were completed in the first quarter and in the second quarter? And perhaps what you're on pace for in the third quarter? And then that will be it.

Yes, we put 188 wells on production in the second quarter. I don't have the number from the first quarter off of the top of my head, but we're still in -- heading toward 650 or so. 650 to 700 wells for this year.

Okay, and that includes the wells that were held over from 2011, the ones that you completed in the first quarter?

These are wells we completed -- we put on production in the second quarter.

Okay, and 650 for the year also includes the stuff that was drilled but not completed in the fourth quarter of 2011?

It's pretty much just a run rate number. You look at it in terms of wells put on production or drilled. We always have an inventory of wells that are waiting on completion and waiting to be put on production. Those numbers end up equating.

Okay, thank you.

Our next question will come from Michael Hall with Robert W. Baird.

Thanks. I was going to ask a couple more of mine, and not to beat a dead horse, but I'm thinking about 2013. I think previously you indicated getting to 10 net horizontal rigs, or operating 10 horizontal rigs in '13. Is that still a fair assumption on a net basis post-JV? How should we think about that?

Yes, that would -- right now, we are without a JV, we're planning on going to seven. Start off the first part of the year. With a JV, it will more likely go -- be around closer to 10.

And is that net or a gross operating number?

That is a gross number.

Okay, and then is there any willingness to outspend in '13 a modest amount, given that you're growing deck capacity and you can still drive leverage metrics lower with the growth you're seeing? Or is the mantra literally spot-on with cash flows is going to be the target coming into the year?

No, our long-term strategy is to grow within cash flow.

Okay. And then I guess the last one on my end, think about targeted lateral length. Is that 7,000 the current assumption, or is there -- is it likely to be a little lower than that? Based on field limitations?

Well, I think the objective is to, at a minimum, drill 7,000-foot laterals because there is clearly a very close correlation between lateral lengths and well productivity and EUR. But as I mentioned in the call, we're going to be exploring the use of 9,000 -- up to 9,000-foot laterals in the second half of the year. We'll have more to report as more time goes by as to this correlation. And of course, your lease configuration ends up being a determinant to the extent you can actually drill more than 7,000-feet it takes the lease configuration to do so. It certainly wouldn't be in every case we could exceed 7,000 acres, but the objective of the field rule changes to, in fact, provide for the opportunity to drill at a minimum 7,000-foot wells.

Okay, so that is a fair number for '13 to think about as an average?

It's going to be above 7,000-feet. In other words, 7,000 would be the minimum to the extent you drill some that are above that. You would exceed 7,000 on average.

Okay. And looking at those five University wells, you had frac stages of, I guess, 35 on average. The type curve you're saying is 30 to 35 frac stages. I guess help me think about how you've got shorter laterals, but the same amount of frac stages. How does that really impact then the EUR assumption? Is it just overly stimulated, if you will? Can you help bridge that a little bit?

There is a distinction here between the number of stages prompt and actually the number of clusters in each stage. And so to the extent you extend the laterals, you can still be running 30 to 35 stages, but you would be increasing the number of clusters in each of the stages. Actually --

Got you.

-- you're putting more profit and more fluid away in connection with basically increasing the number of clusters per stage.

Got you. Makes sense. Thanks very much. Congrats.

We'll hear next from Richard Tullis with Capital One Southcoast.

Thank you. Good morning. Just quickly, what were the choke sizes, the typical choke you were using for the 24-hour and 30-day rates for those University wells in Wolfcamp?

The question was -- I'm going to have to ask the question of the guys around the table. The question is the choke size on the typical Wolfcamp initial production rates?

We choked through the choke maintenance during the flowback.

He's asking what size, the initial choke sizes?

Probably average 26.

26. 20/64ths, sorry is the answer.

Okay, great. Thank you. And Tim, where would you likely test those 9,000-foot laterals in the Wolfcamp? What part of your acreage?

Well, specifically, I'm talking about the southern part of the acreage, probably in the boxed areas on slide 10. That is in Upton and Reagan and perhaps over into Irion as well.

Okay.

Basically, it will be a smattering of those wells, depending upon where we have the proper lease configuration.

Okay. And then finally, I guess you picked up a little more acreage in the Barnett combo in the quarter. But given the drop in activity there and I guess the cash demands and better returns elsewhere, is there any potential to look at monetizing that asset at some point?

As I stated earlier, all of our assets are up for sale. And we will determine over time, if we get the right price, what to do. Right now, there is no current plans.

Okay, thank you, Scott.

Our next question comes from the Cameron Horwitz with US Capital Advisors.

Hello guys, one quick follow up. You obviously have your plate pretty here with the Wolfcamp, and I know you had plans to horizontally test the Strawn, potentially the Atoka and Jo Mill Horizon. You still plan to do those tests?

We have actually a couple of horizontal Jo Mill wells that have been drilled. We're waiting on completion of the wells, so we'll have something to say about that perhaps next quarter. In terms of horizontal Atoka, it's something that we're looking at for later in the year or perhaps early next year. We're still some time off before we'll be able to report on results from that activity.

Okay. Thank you.

You're welcome.

And our last question today will come from Mike Kelly with Global Hunter Securities.

Good morning. I've got a high-level strategic question for you. Might be a few years premature, but if you're right and the Wolfcamp play is prospective from the north to south across your 900,000 acres, and you can target up to five zones within the Wolfcamp, your inventory and your capital intensity is going to be mind-boggling, quite frankly. You commented that you won't outspend cash flow or issue equity here. But I'm wondering going forward, how you are going to approach, attempting to pull the present value forward from the 900,000 acres there?

We look out about five years, five to seven years, and so I am not really concerned. We are pulling it forward by doing a joint venture. I mean five, seven years from now, if it turns out that the Wolfcamp is 5 billion to 10 billion barrels itself, then you have lots of choices at that point in time. You can do more joint ventures, can you sell other assets in the Company to fund it. It depends on what commodity prices are doing. It's a nice problem to have. We're focused on the next five to seven years where we're going to get significant growth. And us keeping the northern acreage and a joint venture in the southern acreage, and so it will be something left for future generations around here.

All right. Great. Thank you.

And we actually did have one more participant queue up in the questions. Our final question will come from Abhishek Sinha with Bank of America.

I wanted to ask one question on Alaska. What plans do you have in Alaska in terms of the share, and where do we stand now since we're talking more on the JV right there?

In Alaska, with our two recent strong results this past winter campaign, we're getting prepared to drill a second full rock well on shore next winter. And then secondly, we have a series of frac candidates in the Nuiqsut to perform. So, we're looking forward to the next winter's campaign.

All right. So, do I read that the decision is still on the table, or we're not talking about the decision anytime soon, or?

No, I think it's important for us to sit there, and we have a lot of upside. We need to understand that potential upside before we make any long-term decisions.

Sure. Thank you.

And with that, we have no further questions. I would like to turn it back over to our presenters for any final and closing remarks.

Again, we thank. I know, a lot of questions about the Wolfcamp and the joint venture. We appreciate the opportunity to speak with you all today, look forward to the next quarter and continue to update on this tremendous resource potential in the Permian basin. Again, thank you.

And ladies and gentlemen, once again, that does conclude today's call. Thank you for your participation, and have a wonderful day.