先鋒自然資源 (PXD) 2011 Q4 法說會逐字稿

Welcome, ladies and gentlemen, to Pioneer Natural Resources fourth- quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer;, and Frank Hopkins, 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 to access the slides related to today's call is www.pxd.com. At the website, select investors, then select investor presentations. Today's call is being recorded, and a replay of the call will be archived on the Internet site through February 28.

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 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 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, Mr. Frank Hopkins. Please go ahead, sir.

Thank you. Good day, everyone and thank you for joining us. Let me briefly review the agenda for today's call. Scott will be the first speaker. He'll provide the financial and operating highlights for the fourth quarter of 2011, another strong quarter for Pioneer. He'll then update you on the Company's reserve replacement performance in 2011, and that will be followed by a summary of our 2012 capital program.

After Scott concludes his remarks, Tim will discuss our drilling results and plans for the Wolfcamp Shale, the Spraberry Field, the Eagle Ford Shale and the Barnett Shale Combo play. Rich will then cover the fourth-quarter financials in more detail and provide earnings guidance for the first quarter. After that we'll open up the call for your questions. So with that, I'll turn the call over to Scott.

Thanks, Frank. Good morning. We're on the highlights on page number three. We had another great quarter in the fourth quarter of '11 with adjusted income $147 million or $1.19 per share as compared to consensus of $1.03. This does exclude some mark-to-market derivative losses of $22 million, and also some unusual items of $1.94, $236 million.

Fourth-quarter production, we're at the high end of 140,000 barrels of oil equivalent per day. We are moving South Africa to discontinued operations. That would put us at 137,000 barrels of oil equivalent per day. We have a process that's underway and should be completed by the first half of 2012. That'll be the divestment of our only remaining international asset.

Again, production was up 12,000 barrels of oil equivalent per day, up 9% versus third quarter. Also, 19% quarter-to-quarter on oil growth. Primarily related to growth in the Spraberry, Eagle Ford Shale and the Barnett Shale Combo. For the year, we averaged 124,000 barrels of oil equivalent per day. This includes our discontinued ops at South Africa. We're up 14% versus year-end -- the full year of 2010. If we exclude discontinued ops we're up 16%.

What's more important, Tim will talk more about it in detail. We drilled our second successful horizontal Wolfcamp Shale well, performing exactly like the first well. Both wells are above expectations, this will probably end up being one of the largest oil shale plays in the US. We are the largest acreage holder in that play, with well over 400,000 acres.

We're continuing our successful deeper drilling of the Strawn, Atoka and Mississippian with about half our wells going to these areas or more in 2012. Continued to add additional frac capacity, totaling 70,000 horsepower in both Spraberry and Eagle Ford in the fourth quarter.

Again, delivered great drillbit finding costs, drillbit reserve replacement, 313% reserve replacement, 148 million barrels of oil equivalent, at a drillbit finding costs of $13.83 per barrel of oil equivalent. Also a big achievement, reaching investment grade by S&P, and also moving our debt-to-book down to 26% at year-end 2011.

Going to slide number four, we are increasing our annual production growth of 23% to 27% from '11 to '12, as compared to the 22%. It does exclude South Africa. The primary reason for the growth increase again is the horizontal Wolfcamp play, and the ramp-up there.

We continued to high grade our liquids rich drilling to optimize returns in response to low gas prices, we'll talk more about it with the activity, but obviously focusing on the higher capital efficiency and liquids rich drilling in the Spraberry, horizontal Wolfcamp Shale and Eagle Ford Shale primarily.

We are reducing our rig count of expectations, we're keeping it at 12 rigs during 2012, moving back to our planned goal of 14 rigs in 2013 in the Eagle Ford, maintaining Barnett Shale at 2 rigs and we'll be moving to 4 rigs toward the end of the year, going into 2013.

Targeting 20% compounded annual growth rate, which is an increase from 18% previously, and also expect to achieve a 25% compounded annual operating cash flow growth rate for 2012 to '14. We'll be adding more frac capacity than we had planned during 2011, 70,000 in the Spraberry, for a total of 300,000 horsepower, and that's primarily due to the ramp-up of the horizontal Wolfcamp play.

With the recent run off of several weeks ago, of WTI, we've added some more oil derivative positions for the years 2012 to 2014, primarily the three ways that we have been doing in the past.

Slide number five on reserve additions, again, strong finding costs. We added 148 million barrels of oil equivalent from the drillbit at a finding cost of $3.83 per barrel of oil equivalent. Again, significant drilling campaigns in Spraberry, Eagle Ford, and Barnett Shale Combo play.

Now, all in finding cost of $17.51 per BOE. Reserve mix, 99% plus, obviously by the end of 2012 will be at 100% in the US. 60% liquids, 40% gas, 58% proved develop, 42% PUD. Proved reserve production ratio of 22 years, and a proved developed reserve production ratio of 13 years. You can see a breakdown in the table. Again, with Spraberry, more than -- continues to be the big driver. Eagle Ford is picking up significantly, also improvements in both Barnett Shale and Alaska.

Going to slide number six, as I mentioned earlier increasing our production growth target, you can see we're picking up from -- up to 22% previously, going up to 23% to 27% for the year 2012. And going from 18% to 20% over the next three years.

Also an important point, we're increasing our liquids from previously shown. We've moved our -- going out, we're already at 56% liquids fourth quarter. Moving to 65% liquids in 2014 which was previously at 60%. Again, with a focus on liquids rich shales.

Operating cash flow growth, going from about $1.5 billion at $100 oil and $3 gas including our hedges, and we expect to receive $2.2 billion cash flow, on up to the $3.3 billion. As you can see, we're already getting 80% of our revenue from liquids, and in 2014, we'll be at 90% revenue from liquids. Achieving a 25% CAGR over that three-year timeframe.

Going into our capital spending for 2012, and cash flow in slide number eight, capital program of $2.5 billion, that includes a little over $1.5 billion for Spraberry vertical. Even though we made comments about slowing down on the vertical program, we are actually increasing the number of wells. We drilled about 690 wells in '11, we're going up to 750 wells vertical in 2012.

The reason for the slowdown primarily is the ramp-up of the horizontal Wolfcamp play, where we're going to spend $275 million in that play. That includes $25 million for seismic and coring. Even though the returns are very similar between the two programs, we get a lot more production per dollar invested in the horizontal Wolfcamp Shale play. And especially even more so if we're performing above expectations.

We're also spending $100 million for infrastructure in the both Spraberry and horizontal Wolfcamp play, primarily expanding two plants. Those two plants will be up 320 million in capacity, we're building essentially two new plants, one in Midland County and one in Martin County to handle both the residue and the NGLs coming out of the rich gas from these two plays.

Eagle Ford, we expect to carry to continue through the end of 2012, we'll spend about $130 million. Barnett Shale Combo, $215 million for two rigs. 103rd a little increase from Alaska, as we have mentioned we are drilling two key wells, one in the Torok, a discovery we made about a year ago with a large selective frac job, and then we'll be drilling an exploration well somewhere between 100 million and 200 million barrel potential in the same area to the Ivishak. Two key wells for Alaska.

In addition, $120 million includes land capital for existing assets, and as I mentioned earlier we're increasing our vertical integration, we have been mentioning about 50 million for the year 2011, we will be going up about 100 million both increasing horsepower because of the horizontal Wolfcamp play, and we're adding more pulling units in West Texas. Capital programs funded from operating cash flow of $2.2 billion, and again, with equity proceeds of $300 billion (sic -- see presentation slide) for the $2.5 billion CapEx program.

And finally on slide number nine, investment highlights, with the eventual sale by mid-2012 of South Africa we'll be at a US asset base for the first time in about 14 years. Obviously most of it focused on Texas. With our liquids rich shale plays, 2012 drilling program is focused on the Spraberry vertical play, Wolfcamp Shale horizontal play, Eagle Ford and the Barnett Shale combo play.

Again, forecasting 20% CAGR production growth at 25% CAGR through 2014. Again, seeing substantial improving returns by being vertically integrated, saving over $450 million plus per year, that number should increase in 2012. Again, great hedge positions in both oil and gas in 2012 and beyond. And again, a strong financial position with debt-to-book of 26%, and achieving investment grade during the quarter. Let me turn it over to Tim, to talk more about operations.

Thanks, Scott. We did have a very strong operational quarter in the fourth quarter of 2011, across our entire asset base. And that includes our assets in Raton and the mid-continent area, but for today's purposes I'll be talking principally about our Texas-based growth assets and I'm going to start with discussions regarding the horizontal Wolfcamp play.

Although it is early in the play, we're continuing to see encouraging signs and specifically in this report, we're talking about a second horizontal successful well that was in the neighborhood of 1.5 miles away from our first well. The wells were completed and drilled and designed essentially to be identical and what we've seen importantly is almost identical results.

They only were drilled to 5,800 foot lateral lengths, that's considerably less than we'll be drilling as we go forward, and I'll talk more about that in a minute. And with only 30 stage completions. With that said, we're very confident that by the use of micro seismic, that we once again successfully landed the wells, or successfully had the fracs in the entire 500 foot -- 800 foot zone.

So it's actually going exceptionally well on these two wells and you can see that as you go to slide 11. In which case we show the production from these wells in the early stages, and you can see, they're almost identical as I mentioned earlier. What's really important about the -- this production to date on the first well is that after about 90 days, we've seen about 45,000 BOE of production in that well. That's about seven times what we would expect from a normal Spraberry vertical well over that same 90 day period.

So that seven to one ratio is important because as we look ahead and go looking forward to the development planning, we're looking at about a four to one ratio in terms of the cost of the horizontal well compared to a vertical well. And so that gives us some confidence looking forward that we may in fact be showing evidence that we're getting capital efficiency in the horizontal wells.

If you take a look at the graphs of the two wells, first of all these numbers that you see in terms of production are well above our expectations for these wells and well above the type curves we anticipated. You'll also note as you look at the first well, which is depicted in the red, that it has been relatively flat. A flat production profile. And this well is still on natural flow. This is a very good sign for the ultimate productivity of these wells, especially considering they are under natural flow.

As with all shale plays, this kind of consistency and predictability are an important component of value. And I think what we're seeing as I mentioned is empirical evidence that these horizontal wells may in fact lead to capital efficiencies as compared to our vertical program.

On the next slide, in fact the next couple of slides, they deal with our plans moving forward in the play. And you can see on the map on the right, this play has immense aerial expanse, and you can see the two wells we drilled in the Giddings area to the north and west some 60 miles away from where the rest of the activity is taking place in the play.

It's clear we have over 400,000 acres that are prospective for the Upper and Middle Wolfcamp interval that has been the target of the first two wells. We're the largest acreage holder in the play. And it's also clear from the data we have that this horizontal play actually extends farther northward as well. In fact, perhaps as far north as the northern limits of Midland County.

One of the most important statistics regarding this particular play is it's probably one of the most prolific shale plays in North America when you measure it in oil in place. And it's consistent across substantially all of our acreage that we have somewhere between 50 million and 100 million barrels of oil in place per section meaning the productivities from these wells should be outstanding.

As we look forward, and I mentioned this earlier compared to the earlier wells, we will be designing the wells with about 7,000-foot laterals, probably 35 stages, in terms of the fracs. In the early days, we are penning in EUR of 350,000 to 500,000 BOE per well. Obviously, we have to see a lot more data before we're able to claim exactly what that number is. But so far, the first two wells are beating the type curve.

In the early stages of this year's campaign, we'll be drilling what we refer to as science wells, those include cores, and in many cases also microseismic and extensive log sweeps. And so we're looking at well costs therefore in the neighborhood of $8 million to $9 million probably for the first half of the year for several wells. And dropping that down to more $6 million to $7 million as we get into more of a development campaign and out of the science program.

Importantly, the returns look as good or better than our vertical wells, and this may owe to the fact that we think we're seeing some capital efficiency in the horizontal program.

If you go to slide 13 then, our near-term plan is to focus on the southern 200,000 acres that are depicted on the map. The objective here is to preserve lease hold. This is in an area where vertical drilling economics have been challenged, and therefore we have much drilling to be done to preserve the lease hold in the neighborhood of 80 to 90 wells between now and the end of 2013 to hold that acreage.

Of that, we expect about 30 to 35 wells to be drilled this year. And toward that end, we have three rigs running today; one well is actually waiting on frac, which will be started up next week; and two other wells drilling. These are the 7,000-foot laterals I mentioned in southern Upton and Reagan counties as shown on the map.

We have already importantly contracted up to seven rigs that will be here by year-end, and we'll be heading towards 10 rigs as we get into 2013. We also are acquiring about 260 square miles of 3D seismic. This essentially is being done in order that we can avoid geo-hazards in our development plan. Suffice it to say, we are getting a lot of confidence in the horizontal Wolfcamp Shale, and I think it's clear it's going to be the fourth leg of our oil-based liquids-based high return growth assets in the state of Texas.

But as you turn to 14, lest we not forget we are continuing a massive vertical campaign in the Spraberry in 2012. And in most every case, deepening the wells and we've now proven beyond a shadow of a doubt, that the deepening of the vertical wells is still paying off very handsomely.

Slide 14 shows the results of last year's drilling campaigns, including in the Strawn where we completed about 246 of the wells out of that total of something like 700 wells in the Strawn. And the data is very definitive. We see about a 25% increase in production during the cumulative 12 months compared to the offset lower Wolfcamp wells where the Strawn was not completed. And that gives us confidence in about a 30,000 BOE incremental EUR for those wells that have the Strawn. And we think that's 50% to 60% of the acreage.

In the Atoka and Mississippian, these are deeper targets and actually from a geographical standpoint are further to the north. We completed 18 wells in the Atoka, and believe that they are adding somewhere in the neighborhood of 50,000 BOE to 70,000 BOE and will be prospective on 25% to 50% of our acreage. Mississippian, which is even deeper, we completed four wells, in that zone, and believe we have potential incremental EURs of 15,000 to 40,000 BOE, where it's prospective on about 20% of the acreage.

So you'll see a massive vertical campaign including the deepening as shown on slide 15, out of 750 wells, you can see to which interval these wells will be drilled, show on the left is actually the deepest interval that's going to be completed. So the way you read the table is that in the Wolfcamp about 50% of the wells will be drilled to the Wolfcamp, the deepest zone will be the Wolfcamp. Meaning we would not be deepening to the Strawn, and we show the blended well cost of that in the IRRs on slide 15.

About 20% of the wells will be TD within the Strawn, and another 20% in the Atoka and 10% in the Mississippian, realizing that in many cases where we're completing in either the Atoka or the Mississippian, we also maybe including a completion in the Strawn.

Overall, what this gives us is about a $1.7 million to $1.8 million average well cost if you do the blending of all those completions. And a very attractive IRR nearing 50%. So it's clear that the vertical program, specifically with the deepening of the wells, will be a major contributor to Spraberry growth.

So if you look to slide 16, what does that mean in terms of growth? You can see we had really quite an outstanding fourth quarter, hit the top of the range about 53,000 BOE. And as Scott has already alluded to, we will be reducing the vertical rig count just through the year, simply by letting go existing rig contracts as they expire, that begins mid-year and continues through the end of the year.

And at the same time and in parallel with that, we'll be increasing the horizontal rig count as I mentioned earlier from some three rigs up to seven rigs by year-end. And as a result, that will allow us to drill the 750 vertical wells and 30 to 35 horizontal wells this year.

Importantly, as we look ahead, we're beginning to include in our modeling production impacts from Strawn, Atoka and Mississippian deepened wells, and additionally, we are starting to forecast in the impact of production from the horizontal Wolfcamp Shale wells from the South.

Now I'm going to turn to slide 17, and that's discussing South Texas and the Eagle Ford Shale production. Our Eagle Ford Shale team had an excellent operational year in 2011 as well where they drilled 111 wells and put 92 of those on production. We're currently running 12 rigs in the field; our objective, as Scott has already mentioned, is to keep 12 rigs running and drill a 125 well program.

At one point in time, we had considered drilling 25% of the program as dry gas wells, but in response to what's happened with natural gas prices, we're delaying that increase to 14 rigs until next year. That will then have us drilling only about 15% of the wells into dry gas areas, the objective being to control areas where we have substantial additional wells that can be drilled on the lease hold by just drilling the first initial well. So this is really more of a long-term value proposition, and maintenance of optionality when it comes to future gas prices.

We have an increase of the number of wells we plan to actually pump white sand up to about 50% of the wells. Early we had said 30% to 40% of the wells but we've seen good results so far. From about 30 wells in which we used white sand last year, and the performance looked similar to those offset wells where we were pumping ceramic. And so this is a substantial cost savings for us, and accordingly we should see economics improve as a result of that.

We have eight central gas processing facilities online today, and have three more planned as well as some upgrades at three other facilities. Most of that will be done during the first half of the year.

We did see some excellent results from pad drilling. Of course most of the drilling we're doing up-and-down this trend is to preserve lease hold but we have been experimenting with some pad drilling and the results look really stellar. In our first zipper frac, three-well program on a pad we actually got the completions done in 5.5 days. That's about what you would expect to do for one well, if you look back at our track record.

And so as we look forward and we begin the process of getting into more pad drilling later this year, into next year, into 2014, I think you'll see substantial savings and economic benefit from pad drilling.

Turning to slide 18, the ramp-up in Eagle Ford Shale continues in terms of production. And averaged about 20,000 BOE and you can see the increases going forward, and this is even the case when we've maintained 12 rigs in 2012 and had pushed the ramp-up out one year, where we go to 14 in 2013, and then 16 in 2014, and 19 in 2015. The ramp-up is still exactly the same but pushed out one year in the face of low natural gas prices.

Slide 19 is covering the Barnett Shale combo play. We are keeping our two rigs running there, and delaying moving to four rigs, until perhaps the end of this year into early next year. They also did a very good job in terms of operations this year, and I'll show you the production increase in the next slide, but they drilled 43 wells and put 42 on production.

Importantly, looking forward we're going to be increasing the lateral lengths to about 5,000 feet, where we had been averaging 3,500 to 4,000 feet. And accordingly, we are also increasing the average EURs that we see from these lateral wells lengthening to about 460,000 BOE compared to our earlier type curve of 320,000. I think there's a clear benefit and a correlation between the lateral lengths and EURs of the wells.

We are impacted, needless to say, in this play by low gas prices. Not wanting to overspend a combination of our cash flow from operations, and the portion of the equity raise at the end of last year that was for the funding of the Wolfcamp horizontal, our returns have been compromised somewhat by low gas prices, but these two rigs will be continue to drill, basically preserving lease hold and looking for a potential increase into 2013.

On slide 20 then is the production I mentioned, we see that Barnett Shale basically landed in the middle of its range, 6,000 BOE per day in the fourth quarter. You can see that the asset continues to grow even though we're only maintaining two rigs in 2012, and so the punch line is Barnett Shale Combo Play still is a significant oily growth asset for us.

So overall, I'd say operationally the Company is hitting on all cylinders in our four Texas-based oil and liquids resource plays. And with that what I'll do is pass it over to Rich for a review of the fourth-quarter financials and guidance for the first quarter.

I'm going to start on slide 21. As Scott mentioned we had a net loss attributable to common stock holders of $111 million or $0.93 per diluted share for the quarter. It did include unrealized mark-to-market derivative losses of $22 million or $0.18 per diluted share, and unusual items totaling $236 million or $1.94 for the quarter. Principally non-cash items related to reduced gas prices. Adjusted for these items, income would've been $147 million or $1.19 per diluted share, as you can see on the slide there.

Looking at the bottom of this slide, we show our guidance coming into the quarter that we gave out in November. Relative to the middle column there, that shows fourth quarter including South Africa, but excluding unusual items. So going down that list just briefly on the highlights, production was at the upper end of the guidance, as Scott mentioned.

And if you look at expiration and abandonments it's at the higher end of the range, principally related to the seismic data that we acquired for our horizontal Wolfcamp play in Spraberry. And then G&A was at just above guidance related to performance-related compensation. The other items are basically in line with where we forecast coming into the quarter.

Turning to slide 22, price realizations you can see on the bars there that oil was up 5% for the quarter to $91.51. While NGLs and gas were both down for the quarter with NGLs declining 6% to $45.70. Really as a result of declining ethane prices during the quarter, and then natural gas prices were down 17% to $3.37 per Mcf. At the bottom of the slide here you can see the impacts of derivatives and that's there for your information.

Turning to slide 23, I think the punch line here is that really production costs if you look at each of the quarters in 2011, they were virtually flat throughout the year. With fourth quarter being on top of where the third quarter came in. Probably the one item of note there if you look at third party transportation costs, they were up in the fourth quarter, mainly as a result of Eagle Ford ramp up in production, we had higher trucking and treating costs there.

Turning to slide 24, great balance sheet at the end of the year. We had $537 million of cash on the balance sheet, net debt of $2 billion, our credit facility of $1.2 billion is completely unused. As Scott mentioned, net debt-to-book capitalization of 26%, and if you think about the forecast of $2.2 billion of expected cash flow we have very strong coverage metrics as well. I think also that during the quarter we had moved up to investment grade rate by S&P, which reflects our continuing to improve our balance sheet.

Turning to slide 25, first-quarter production guidance, 141,000 to 146,000 BOE's per day, up from where we ended the fourth quarter, and then expiration and abandonments higher than our normal range to 35 million to 60 million, really because it includes two items. One, we had two Alaska exploration wells going down this winter and then we also are shooting some additional Wolfcamp -- horizontal Wolfcamp seismic in the first quarter.

All of the other items are the same as what they've been in prior quarters, other than current income taxes. That is down with moving South Africa to discontinued operations, current income taxes represent state taxes that we'll pay during the first quarter. So with that, we'll stop here and open up the call for questions.

Thank you.

(Operator Instructions)

We'll pause just a moment to assemble the roster. Brian Corales, Howard Weil.

Good morning guys. A couple questions. One, what do you all think -- I know it's very early, but on the Midland basin horizontals, what do you think the optimum length is? I know you're increasing the laterals. Do you have kind of a length in mind or a number of fracs in mind?

Yes. Brian, as Tim said, we're moving up to about 7000 feet. We'll probably try some a little bit longer. One of the critical issues, there's only a certain amount of acreage, especially on the university lands that you can get these long laterals. I think the challenge for most operators is going to be several smaller independents will not be able to get out that long, so there's going to be a lot of probably deal making in the play. But on university lands, where we own a lot of our acreage, it's an easy area to move out 7000, maybe even 8000 feet. So in the Bakken, it's moved out significantly. So where you can move out longer laterals, we'll definitely try it.

Okay. And then you all did mention in the Eagle Ford with going more to white sand, a little bit away from ceramics, one, is there a rule of thumb, I don't know if it's depth or pressure, where you're going to use white sand primarily? And then two, if we fast-forward six, nine months, how much of the pressure pumping or the horsepower is going to be internally owned?

Well, first of all, I think it's clear that we feel like that the white sand is something that's going to be best used in areas that are a bit shallower and lower pressure as compared to the opposite. In other words I think it's going to be a situation where it's north and west in the trend, where we're dealing with a shallower horizon as well as less pressure. And so I think you'll see us for example as you get in DeWitt County, in the Western DeWitt County areas, definitely using white sand. As you get south and east, you get hotter, deeper, and higher pressure. And that becomes an issue. So you'll see us using ceramics essentially to the southeast, and sand to the northwest in the general sense. In terms of horsepower, our second PXD operated frac fleet is just right now getting cranked up. And that will have us at a point very shortly where we'll be pumping two thirds of the wells with Pioneer equipment for the rest of the year.

And can I -- just to kind of follow on that, assuming white sand and -- we'll say two thirds of the pressure pumping, with internal, what does that do for PXD's well costs?

Well, as you know, we use a blended well cost of $7 million to $8 million, something like that. But that includes internally generated pumping services as well as a combination of ceramics and white sand. If you look at the savings on white sand, it's about $700,000 per well. We think we can pump the wells at least $1 million cheaper than a third party. And so that should give you a handle on where we're coming down on the cases where we just use white sand and our own pumping services.

Okay. That's hopeful. Thanks, guys.

Brian Lively, Tudor, Pickering, Holt.

Good morning. On the Eagle Ford volumes, it sounded like you guys were at the lower end of your Q4 guidance. But it seems like the issues are transitory. If that's true, just correct me if I'm wrong on that, but what is the exit rate for 2011 Eagle Ford volumes?

Let's see. I can talk to you about what happened, Brian, real quick in the field. We had a couple situations which I believe are in fact transitory. We had a situation on some of our oilier areas where we were having some paraffin related issues at the CGPs, which have now been alleviated with chemical treatments. So that was inhibiting some production, so we got that back to normal. Also, we had a couple situations at our CGPs where we were dealing with some high line pressures during pinging operations. And accordingly, we were having to review, in fact we're in the process of reviewing, adding central compression to alleviate that problem, and that's something that's-- that we're doing as of right now, we're actually in the process of evaluating putting in central compression. So basically as you said, we're in a situation where these are just transitory issues that we're just solving.

And do you have an exit rate for the Eagle Ford?

Well, it's bigger than 20,000. I promise you that.

Okay. Is it bigger than 25,000?

(laughter) We just don't give out exit rates, Brian.

Brian, it's about 20, like we talked night.

I told you I would try, Frank.

I knew you would.

Kudos for trying.

On the Wolfcamp itself, I'm curious on how you guys defined your original expectations. You guys say that the results are better than what you thought going in. I just wanted to get a sense of how you derived those expectations in context to the overall play itself and how you might see some variability in the rock quality as you go to the north in particular?

Yes. As you know, we have over -- about 900,000 acres in the entire Spraberry, Wolfcamp play, so we have access to over 7000 logs, we've probably got the most number of cores, versus any other operator, we've been there for a long time. So we probably have more data, we have some 3-D seismic data on the shelf. We're buying some more, or shooting some more, so our data source is probably 10 times greater than anybody else. We have people focused on it, and we're in the center of the basin, where the oil is mature, it's very brittle, in the Wolfcamp play. As we have found out through the core analysis, so we have a pretty good feel on how big this play can go. So the reasons -- the Wolfcamp as you get through the Spraberry formation, the gradient increases. And because of that, we're seeing much better performance, as Tim has mentioned, on the production characteristics as both wells are still flowing. At some point in time, we'll put them on either jet pump or pumping units, but they're flowing a lot longer than we expected, pressure is staying higher but because where we had a pressure regime change going from the Spraberry down to the Wolfcamp, so that's helped us also.

That makes sense. So then the two wells, are those the expectations then going forward?

That's going to change, but we're over -- we're drilling wells 80 miles, 70 miles apart, in the play. And we'll be drilling wells eventually to the north. So we will have to develop -- we'll probably -- wouldn't surprise me if we end up having three or four different type curves. Eagle Ford, I think we mentioned before, we've got about 15 different type curves in Eagle Ford, so we may have more as much in that but we expect at least three or four different type curves.

Okay. And my last question, Tim, you mentioned a number of times about capital efficiency as you shift towards the horizontal program. Can you put that in context in terms of numbers? What is the breakeven cost that you're expecting for your average vertical well versus the horizontal program at this point?

Well, I haven't computed breakeven numbers, but I look at it from a simplistic method of analysis, and what I mentioned on the call which is, we think our development drilling run rate for a horizontal well add 6 million to 7 million, which has quite a bit of detail behind it, which represents something like four times the capital of a vertical well is a good number. And the real question is then, what is the productivity of the wells? We're simply at this point encouraged by the early production. We have a 7X on production compared to the vertical well, you get pretty excited about that because it has the possibility that you are actually adding significant capital efficiency. The issue with this is we only know the real answer to your question as we have more time and more production history under our belt so that we really know the answer to the question. What I'm saying right now simply is that it's encouraging what we're seeing.

Makes sense to me. Thank you, guys.

Gil Yang, Bank of America, Merrill Lynch.

Good morning everyone. You commented for the second well that micro seismic told you that all 800 feet of the interval was frac. Can you remind me of what you saw in the first well?

Identical, Gil.

Okay. And can you talk about -- with this well, the second well, on a constrained zone like the first well was?

No. This well did not have any real significant constraints, so from that standpoint, it differed a little bit but right now these wells essentially neither one has any constraints is what it amounts to.

Okay. Is that significant in any way? Does the fact that the first one was constrained, does that suggest that it's actually a better well or you can't--?

I think you really can't read too much into it because the calculation of an unconstrained flow rate is simply that, it's a calculation, it's an estimate, so I think what we need to look at is how well these wells are producing right now, they've got several weeks and months under their belts in terms of data is going to be the real illustrative point.

Can you calculate based on pressure draw down when you're going to have to put the first well on pump?

It looks like right now we're still producing the well flowing as I said, I think it could be within the next few months we'll be putting it on pump is the current thinking.

Okay. And what kind of rate do you think you'll be getting when you put it on pump?

I don't know the answer to that question. It's presumed to be higher. I can't tell you the number, though.

No. I mean, does it drop off to 100 before you put it on pump, or does it -- do you do it at 300 or can you tell?

It's going to be 50 or less. Down to zero, maybe. Flowing pressure.

Okay, okay. All right. And for just a housekeeping question, before I get there, the 100 million to 200 million barrels potential in the Ivishak, was that potential, it's not for that well, right, that's just the one well that --?

That well is looking at 100 million to 200 million barrel prospect in the Ivishak. It'll take more than one well to develop it. But if it's a discovery and still the spell, it could be as high as 200 million barrels plus.

How many exploration wells do you think you need to delineate that opportunity? How many wells would you need to drill to?

One well will determine the size.

Okay. And then how many wells to develop it?

We'll have to get back with you on that.

Then for Rich, maybe housekeeping question, the share count came seems like it hasn't changed but you had this equity issuance. Am I missing something?

Yes. The share count, as you can imagine, Gil is, weighted, average. As it was done at the end of the quarter, it was very little of the new shares weighted into the calculation.

Even for the quarter?

For the quarter, because only had basically 15 days of it.

Okay.

50 to 90. And plus since we had a loss, you don't get all the, you don't have a big dilution effect.

Okay. And so that's -- is that part of it, that there is -- you sort of see some anti-dilutive nature of the --?

That's correct.

Can you quantify that?

I don't have it here in front of me, Gil, but we can get it for you.

Okay. All right. Thanks a lot.

Leo Mariani, RBC Capital Markets.

Hey guys, just wanted to clarify a comment here on the Wolfcamp. Talked about the wells performing above expectations. You guys had an EUR range in these horizontal wellS of 350 to 500 MBOE. So above expectations would that be sort of above the midpoint so kind of above a 425 number or is that kind of above the high end at the 500?

Yes. We're signaling it's above the mid point. Basically. Yes.

That's right.

Okay. In terms of South Africa, obviously you guys announced the decision to sell that today. I know in the past, Pioneer has kind of said that they'd likely kind of produce that out. Is there anything that sort of changed your mind here on that?

No. We basically have had some contacts, positive contacts and we're working through the process. That's what's changed.

Okay. In terms of the Eagle Ford, did you guys see any changes in the EURs for your wells and your year end '11 reserve report versus year-end '10?

No. We've been adding reserves as you know as a result of a large drilling campaign and the EURs are hanging in there.

Okay, so roughly similar EURs there?

That's right.

Okay. And I guess obviously you talked about bumping up your CapEx a little bit here in 2012. To add some midstream, I guess as you grow the Spraberry here, is that something you think might have to recur in the next couple of years where you may have to add another few plants every year or so? Can you just kind of help us out with that?

No. We and Atlas were talking, and since we are partners on two of the big three plants in the Spraberry play, we actually got them to increase. They came to us with a 100 million capacity. We got them to double it to 200 million. A lot of it has to do with this ramp up in the horizontal Wolfcamp play. Looks like the GURs are running about 1000 in the play, when you're making a lot more oil, you are going to add a lot of casing head gas. And so for that reason, then we have another partner up in Martin County. We got them to increase that significantly also. And another plant that we own in Martin County that's coming online here in the next few months. Because of the success in the deep vertical play by going to the Atoka and Strawn and Mississippian. And so this should -- adding 200 million a day in Midland County and adding another 120 million a day new plant up in Martin County, it should give us plenty of capacity for the next several years.

Okay. And I guess are these facilities that you guys our partners on and you own like half of these, roughly? Is that right, hence the CapEx?

27% on two of the plants, and about 30% on the other plant. So roughly around 30% on all three plants.

All right. Thanks, guys.

Michael Hall, Robert W. Baird.

Good morning. Just quickly in the Eagle Ford, makes a lot of sense obviously to defer the dry gas activity. But -- a little curious as to why not reallocate that within the Eagle Ford to more liquids rich opportunities? Are there kind of just logistical constraints to that? Or midstream or I guess what's the thinking around that? And then also is there any potential acreage loss associated with that reduced dry gas activity?

Yes. The second part of your question Tim did mention there's a few thousand acres, not much, that we are dropping-- I don't expect anybody to pick it up so we always have the opportunity at some point in time to go back and pick it up, see the acreage costs come down. The first part of the question the primary driver we did not increase Barnett, and also Eagle Ford, even though the economics are great is that we just didn't want to increase our CapEx. We have the bank facility to be able to do it but we just want to get into a big overspending mode. So to meet, we're already growing 23% to 27%, and we just don't think we're going to get paid for it if we grow anymore much more than that too. So it's a combination of capital efficiency and those bigger reasons.

Okay. Makes sense. Just basically staying within cash flow, not getting too far ahead of yourself.

Exactly.

I guess in the Wolfcamp couple quick ones, when would you expect to test that acreage out near Irion? Or like right on the border of Reagan and Irion?

We're going to be testing essentially our entire 200,000 acres by the end of '12.

Okay.

Going now down South -- we'll eventually move out to the southeast, at some point in time.

Okay. And then in slide 11 in the footnotes there, you provided a couple different NGL yields, I'm just curious -- sorry if I'm not reading it correctly. Which one should I be thinking about as a more likely case or should I be somewhere in between them or how should I think about that?

The first one, the 215 barrels per million and 42% shrink is the one that is probably the more generic answer.

Okay. And then finally, I guess are you all targeting any other -- or still thinking about targeting any other horizontal intervals or are we kind of hands full with the Wolfcamp at this point?

Yes. We have talked about in the past, either on this call or individual meetings about there is some activity by other operators in the horizontal Atoka, but so we expect at some point in time the team is working up potential locations for that. And we also have a team looking at other shale plays in the area. So we think that with the Spraberry and the Midland basin at 20% of the US oil reserves, that there's huge potential in other shale plays in the basin.

One addition to that is we are looking at the potential to actually go into one existing Spraberry spray zones called the General Mill which we think also could be an area where horizontal drilling could enhance productivity so that is something we'll probably do some -- a couple of wells in this year, it's still under planning.

Okay. Great. I guess actually one last one for me, I think you said 750 wells in the vertical program. Is that a gross number or net?

That's gross numbers.

Okay. Thank you.

Net and gross are essentially the same for our Spraberry vertical drilling.

Dave Kistler, Simmons & Company.

Morning guys. Real quickly in the Wolfcamp, you had talked about it as potentially being your biggest oil play in North America. Where do ultimately see rig count going there? Not just for yourselves but maybe industry wide. And then given you guys have your strategy of vertical integration, will you be looking at picking up higher horsepower rigs to do that kind of drilling over time? Can you just give us a little more color around that?

Yes. It definitely has huge potential. I think the things that we're going to -- the main thing that's going to hold it back is the current land position. Most of it is held by, except by ourselves, a very few small large operators. It's not totally different from Eagle Ford where people can come in and buy a lot of acreage. You cannot buy a lot of acreage in this play and so it's going to take a massive effort to be able to put together small independent operators, a lot of people just have-- they may have a Spraberry well on a 40 acre or 80 acre tract, the problem is you've got to put together a section and a half, maybe two sections before you can even drill an economical horizontal Wolfcamp play. That's going to be hard for a lot of people. So this play for that reason will probably go much slower than the Eagle Ford but its got the potential to ramp up eventually to easily 100 rigs over the next three to five years, and maybe even 200 rigs. But it's going to be much, much slower pace versus the Eagle Ford play, simply because of the current land position.

And most of our rigs that people have to pick up are 1500 horsepower, there's very few of those out in the Permian Basin. So these are going to have to be new builds or come from plays like the Haynesville. So we've got to see a continued significant drop in that dry gas rig count in these plays, and that will allow the Wolfcamp play or the Wolfcamp play over in the Delaware basin also to pick up a lot of these 1500 horsepower. So there is a shortage of 1500 horsepowers for that reason, and another reason it's not going to ramp up as fast as the Eagle Ford.

Does that mean you guys are going to pursue potentially picking up some 1500 horsepower rigs on your VI strategy? Or are you going to be looking to contract at this point?

The ones that Tim mentioned already going up to 10 rigs we're contracting.

Okay.

So going to seven, eight, by the end of this year going to 10. We'll be contracting. Most of them have already been contracted.

Okay. That's helpful. And then you've done 34 rigs on down spacing in the Permian, and water flood results continue to get better on the margin. When do you guys kind of call victory on moving from 40 acres to 20 acre spacing and when do you start prosecuting maybe a more aggressive water flood?

Think the fact is we're continuing to drill 20 acre space wells this year and next year and the results look very, very good. And I think we've proven that this technology where we're deepening 20 acre wells and creating production which is essentially equal to offset 140,000 BOE locations that otherwise were not deep and is something that's going to work going into the future. We'll be continuing to drill some 20 acre wells this year, I think the objective still is we've got several thousand 40 acre wells to drill so we may as well focus on those first. I think the fact is we've proven that 20 acre locations are going to be economic.

On the water flood, we're still continuing to see very good results, and we're starting to see additional response in other wells that had not yet responded, and so I think that's gone exceptionally well. We have a team of people that are working on about a 20,000 to 25,000 acre flood that we may be contemplating starting up here at the end of the year, a little later in 2012. But suffice it to say I think we can call it a success, and right now we're just assessing which is the next direction we're going to go. I think it will be later this year before we can pull the trigger on that.

Great. That's helpful. And then in the Spraberry, where you're looking at co-mingling various zones, can you talk a little bit about how these overlap -- you've given us prospectivity for each area, but can you talk about how much of them overlap, just so we can kind of think through how we model out field development on a longer-term basis?

I think if you look at the slide that I was talking about, Dave, slide 15, the important point about this slide in terms of overlap is you typically -- it's very seldom that you see a situation where you have both Atoka and Mississippian, just the way the aerial extent is. So to the extent that we are drilling a Strawn well, this would be more areas to the central and southern part of the acreage. As you go north, you encounter Atoka and Mississippian and in a lot of cases Strawn as well. So what you have to realize is you can't just sum Strawn, Atoka and Mississippian, but in many cases, you're going to have the ability to complete in both the Strawn and the Atoka or in the Strawn and the Mississippian.

Okay. That's helpful. I appreciate it, guys. Thanks so much for the added color.

Amir Arif, Stifel Nicolaus.

Thanks, good afternoon guys. Just a few quick questions. First, in the Wolfcamp Shale, can you tell us what the liquids cut is for the Wolfcamp Shale wells versus your typical vertical wells?

They're both about 90-10. 90% liquids. 10% gas. The Wolfcamp maybe a tad higher than the vertical wells.

Okay.

And it's got also higher BTU content so far. On the first two wells. Moving toward 1500 BTUs versus 1400 on a vertical well.

Okay. And can you just give us some color of how you see the geology or the expectations as you move further southeast from where you did your first two wells towards Reagan County?

We have 60, 70 wells that have already been drilled by other operators. So we have that data. A lot of that data has to be filed with university lands. And we already have access to that data so that's why we are highly encouraged even though we have logs in the area, but the production results from both El Paso and also EOG are very good results.

But did you expect them to get better than your original drilling area? Or similar?

I think we've seen some curves overlying our curves. The wells are coming in about the same. But I think because we're deeper, that it looks like that we're -- you have to look at the same wells with the same lateral to get apples and apples.

Yes.

It looks like our Giddings wells, based on their lateral length and the depth of that they are in are doing better than these other operators. The reason is, is that we're a little bit higher depth, so we get a little bit better pressure regime. But as we move toward them, we should have similar expectations.

Okay. Sounds good. And then just a question on the vertical side, as you've -- you've been co-mingling all the way down, but as you go to some of the deeper zones in the Atoka or Mississippian are you still able to co-mingle all the zones or do you have to sort of add the zones one at a time in terms of the shallower zones?

We are allowed to co-mingle all the way down, not including the Atoka, so we can co-mingle the Strawn, and we are going to the commission in February and March, for a new set of field rules. To allow us to co-mingle all the way down to the Atoka. And we're also coming up with a set of field rules for the horizontal Wolfcamp play. And those have been filed, hearings are in February and March.

Okay. And then just one quick question on the Eagle Ford, just in terms of the dry gas, the acreage exploration, is that going to be -- is that a big bigger issue in '13 or was '12 the big issue? I'm just trying to figure out what percentage of your drilling CapEx in '13 based on what you have so far is going to be dry gas?

Of course we haven't made any decisions on 2013 yet, but we will face more expiries of lease hold if we were to decide not to drill a significant number of dry gas wells. Remember I mentioned earlier in 2012, we were talking about drilling 25% of the wells to the dry gas zone, other than for the fact we've had this gas market we've been facing so now we're down to about 15% of the wells. We would have to drill a higher percentage next year to preserve lease hold so to the extent we do not drill more than 15% this year, we will not have significant loss of acreage. We could have higher acreage amounts lost next year if we were to the same.

Okay. So you're not really pushing that '12 drilling over to '13 right now? You're letting a little bit of that expire but '13 would face --

It's very insignificant. We're also working on trying to renew some of these leases with cash, which we think is the better way to go than drilling wells on lease hold, and to the extent we can do that, we will. But that would leave us having relatively low amount of acreage that would have to expire, less than 10,000 acres.

Sounds great. Thanks, guys.

Brian Singer, Goldman Sachs.

Thanks, good morning. Couple of questions on the gas percentage in the production mix. One is just following up on the last question there. If you look at the first Giddings well, in the Wolfcamp, how, if at all, has that percent gas in the mix has changed especially in recent days? And do you expect any change over time relative to the 30-day rates you've reported from the first two wells?

So the gas-oil ratio in both wells are about 1000. On our first well, we did not have test results back on the composition of the gas. So we used roughly a Spraberry vertical well in the initial NGL calculations. So it turns out we were low. So the first well and the second well are the same. The BTU content is moving toward 1450 to 1500 BTUs in both wells versus 1350 to 1400 in a typical Spraberry well. So we gave out a vertical well composition with our first horizontal well. But now with the composition of both wells taken, they're both up to 1450 to 1500 BTUs.

And should we expect a greater decline in the liquids relative to the gas? In other words, should over time, as the well goes through its normal life it should become a little bit more gassy or do you think that ratio holds?

No. When you move down to the southeast, you'll see EOG approach -- they're announcing higher gas oil ratio wells, it just happened to be as you move down toward that area, the vertical wells are gassier, and so you are going to get more gassy, in those areas, but I don't expect it up in this Giddings area to change.

I'd comment, Brian, just simply to say that it's too early to know but if you look at vertical Spraberry history, which includes many more zones contributing than just the Wolfcamp, you do tend to see slight increases to the GOR through time on the production of the well. We don't know whether that applies here or not though, until we see more data.

Okay. Thanks. And then in the Eagle Ford, since it looks like it's essentially entirely delaying the gassy zone, the dry gas side, how should we think about what your production mix would look like in terms of what percent would come from that from dry gas in the context of your overall guidance in 2013 versus where you are right now?

If you look at our current production there, I don't have the exact number but I know that overall, we look at about 40% gas in the production mix. And that's drilling the liquids rich wells, so I think when you then mix in about 15% natural gas drilling, dry natural gas drilling, that could go up slightly but not in a significant amount.

Great. Thank you.

Dan Morrison, Global Hunter Securities.

Good morning, thanks. I think probably everything's been asked and answered by now, but the one question I had regarding expectations for the horizontal Wolfcamp performance that are baked into your outlook, I know that's going to be a moving target, but when we're thinking about your projections and guidance, what kind of rate assumptions do you have baked into that for horizontal Wolfcamp wells?

Again, it depends on how many wells, Dan, are actually put on production this year. But our average, we're out with now is about 2000 BOE per day average for the year. Realizing that because we have three rigs running now, we'll have seven by the end of the year, there's a significantly back weighted curved. So I think the way to think about it is we're just ramping up from -- with these first two wells having been drilled as we add then 30 to 35 wells in terms of drilling, how many will be on production by the end of the year? I think the main message here is the bigger impact is on 2013 than it is on 2012.

Right. But when we think about individual wells, what's your -- you alluded to type curve or kind of standard wells that these were beating. Where is your sort of, your planning well?

Well I think it's a little bit hard to answer that question. That's why we're trying to be not very specific, Dan, because we've shown you the exact production from two wells. That's the limit of the data we have other than looking at offset operators data. But I think you're going to see the natural declines on these wells. What's interesting about the wells we drilled, it's been what relatively flat over the last few weeks of the production. So it may be they over performed, but we kind of have to beg off on details on that because we really need to have the data before we can give you the exact answer.

Or you just make things up. One other question about that play. How do you all see it working out to the edges of the basin as you come to the shelf margins based on your look at geology so far?

Well, Cheatwood is here and he can answer the question if I botch it. The point I would make is, as I talk to the geologists about this, in the sweet spot which is a lot of the areas we're drilling right now, you have 800 foot section in this Middle and Upper Wolfcamp. But the Wolfcamp is so significant, so ubiquitous that actually as you go towards the edges of our field areas, you have a reduction of that thickness but it's not significant, it goes down to like 700 feet, so really you're just talking about areas that are sweet spots which are associated with thicker sections being that 800 foot section, and that correlates well to oil in play. So I think it's the fact that you're going to see this play expand from an aerials standpoint as we go forward, but right now we're focused more in this central area where we know we have upwards of 100 million barrels of oil in place per section.

Great. Thank you very much.

John Herrlin, Societe Generale.

Just a quick one. With Wolfcamp, you said in the release you were running micro seismic on the horizontal wells. Do you plan to do that on every well, or just until you get a good sense of what the fracture patterns should be in terms of the intervals? And how much does the micro seismic cost?

The answer to your first question is that we were -- we'll be doing sporadic micro seismic as we're drilling in various areas. If you refer back to the math that's on slide 13 you'll see there's actually three specific areas we're going to be drilling and in those areas, we want to make sure we have good micro seismic data. In terms of the specific areas we're going to be drilling and once you have good data and understand the frac propagation with some data points, I think we're good to go in those areas. In terms of the cost, it's about $400,000 to $500,000 per well.

Thank you, Tim.

You're welcome.

Richard Tullis, Capital One South Coast

Thank you, good morning. Tim, I noticed that the gas component of the Barnett Combo wells dropped I guess from 75% previously to about 60% now. I know you're doing the longer laterals but what's the key driver there?

Our data shows basically they're the same from looking back through history, so I'm not sure where you're getting that data point.

I was just looking at one of the prior releases. But that's fine. I could check with Frank later on that.

I think for some time we've had 42% gas in the mix and 58% liquids. I think that that's what the slides continue to show.

And looking forward, cash flow versus CapEx, beyond 2012, what are you expecting using $100 oil, $4 gas, what are you expecting CapEx wise to generate the growth that you're projecting out now for 2013, 2014?

I think the only -- the two increases going into 2013 will be in the Eagle Ford going up to 14 rigs and also our carry will be going way in 2012. So in 2013, the rig count increasing there and the carry going away will be the big increase in our CapEx, but the cash flow is expecting looks like about $2.8 billion, so we'll be as close to cash flow as we can. Obviously, there will be a ramp -- continued ramp up, adding three more rigs going into the horizontal Wolfcamp play. That will be a little increase. We'll end up being very, very close to our cash flow in a $100, $4 scenario.

Okay. And then 2014 you could be free cash flow positive?

Yes. Going into '14 and '15, more free cash flow positive.

Okay. That's all I had. Thanks a bunch.

Ladies and gentlemen, that's all the time we have today for our question and answer session. I'd like to turn the call now back to Scott Sheffield for closing remarks.

Again, thanks for being patient and listening to us during the quarter. Really another great quarter. We're looking forward to seeing everybody out on the road at some of the conferences that are coming up. Again, thanks.

Ladies and gentlemen, thank you for your participation. This does conclude today's conference