先鋒自然資源 (PXD) 2010 Q2 法說會逐字稿

Welcome to the Pioneer National 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 Daley, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Vice President of Investor Relations.

Pioneer has prepared a 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, and then select investor presentations.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's new release on page two of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission. Please note this call is being recorded.

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

Good day, everyone. And thank you for joining us.

Let me briefly go over the agenda for today's call. Scott's going to be up first. He will review the financial and operating highlights for the second quarter of 2010. Another solid quarter performance for Pioneer. He will then comment on the Company's plans for the remainder of this year and look beyond into the next couple years out. After Scott concludes his remarks, Tim will update you on drilling results and plans for the Spraberry and the Eagle Ford shale. Rich will then cover the second quarter financials in more detail and provide earnings guidance for the third quarter. After that, as usual, we will open up the call for your questions.

So with that I'll turn the call over to Scott.

Thank you, Frank. Good morning. We appreciate everyone taking the time to listen to us in this call.

On slide number three on highlights, Pioneer had adjusted income of $51 million, or $0.43 per share, as compared to consensus of about $0.42 per share. Excludes net gain from unusual items at $33 million. After tax that's primarily from the interest we received from the IRS from our deep water cell several years ago, an addition on the Alaska PPT tax credit. Excludes non-cash market-to-market gain of about $84 million.

Our production for the second quarter earned 13,500-barrels a day equivalent. We are continuing to see strong production growth in Spraberry, Eagle Ford and Alaska. This has been offset by some unplanned curtailments and taps up in Alaska. The pipeline and Mid-Continent gas processing plant downtime, roughly about 1500-barrels a day. We will talk more about it later, but obviously we are on track, and expect significant production ramp-up in the fourth quarter, in the first quarter of 2011, fourth quarter of 2010 from accelerated Spraberry, Eagle Ford, Alaska and recent Tunisia results.

The Spraberry program is on schedule. We are running 20 rigs. We will be close to 30 rigs by the end of the year. Tim will talk about some obviously excellent results we have seen in our recent testing of the lower Wolfcamp and the Strawn formation. We are very excited about that. Eagle Ford, we are at five rigs. We will be at seven rigs at year end. Obviously the most important thing that happened during the quarter was the transaction with Reliance. That allows us to accelerate, protect our acreage, our drilling, in the Eagle Ford shale play. Pioneer feels like having two of the best oily plays in the US will be accelerating activity significantly. We are at 25 rigs in those two plays now. We have already contracted the 13 rigs. We will be at 38 rigs in those two plays by the end of this year, and we will be at 50 rigs by the end of 2011 in those two plays.

Next item, very important also. We drilled two successful operated wells in Tunisia. We are currently drilling the third well. We will report the total results sometime in September, October, later, in regard to as we get wells on production. But I think the most important thing is that we have had a discovery in the Anaguid block, which is over 0.5 million acres, which opens up a whole new oil pathway up into that block up to the north. Obviously we are very excited about that well and that discovery.

We have increased our gas derivative positions for 2012 and 2013. Again, we are starting to see more and more producers hedge out further, like we have been doing for the last several quarters. We are now 80% hedged in 2011 with upside to $100 on oil. $8.50 on gas. And we are pretty much protecting $75 oil and $6 gas, on the downside. In 2012, we are about 63% hedged now, with upside on oil to $120, and gas up to $8, protecting a floor of $6 gas and $80 crude. We are starting to layer in some hedges for 2013 on both oil and gas.

Finally, financially, we reduced our debt by $279 million during the second quarter. We are down to close to our target of 35% debt-to-book. We are now down at 37% at quarter end. Strong balance sheet, strong financials.

Turning to slide number four. Forecasting 15% compounded annual growth rate from the years 2011 to '13. Obviously what helps this, we got two great assets that will be climbing -- each one will be climbing up to over 100,000 barrels a day each, both in the Spraberry, Eagle Ford, over the next 10 to 12 years. The fourth quarter, we are still on track to grow 10% plus from fourth quarter '09 to fourth quarter '10. Obviously that's driven by the Eagle Ford processing plants and ramp-up of our CGPs, which Tim will talk about, coming on in the fourth quarter of 2010. Continued Spraberry over-performance, as we are seeing now with recent results, Alaska ramp-up and getting our recent Tunisia successes on production in the fourth quarter.

Drilling capital of $960 million. Obviously we have kept that flat. We don't really see any increases in our capital between now and the end of the year. We think it is important to have a free cash flow model as we have. Going forward, again, we are spending well within our cash flow. Again, we are one of the most liquids-rich companies, going from 45% in 2010 to 55% in 2013. One thing interesting, we averaged about -- in 2006 to 2009, we averaged about 20 rigs to get the 10% production growth CAGR from '06 to '09. In the fourth quarter of 2009 we were at 106,000 barrels a day. We were at five rigs. Today we are at 27 rigs. Most of them put on recently. Fourth quarter of 2010, we will be at 40 rigs, and 2011-2013 we will be at 60 rigs Companywide.

Slide number five. 2010 cash flow and capital spending. We currently expect about $1.2 billion in cash flow for 2010. That does exclude the up front cash from the JV of $266 million. It does include our deep water Gulf of Mexico refund of $150 million. Drilling capital of about $960 million spread out primarily among Spraberry, obviously Eagle Ford, and Alaska. As we had mentioned in our call in regard to announcing the Reliance transaction, we are starting a rig up in the Barnett shale with about $50 million dedicated to liquids-rich drilling in what we call the Combo area, with strong returns. That cash flow is pretty well protected.

Looking out in further years, and slide number six, our operating cash flow is going to double by 2013. Based on the current strip, which as I mentioned already, we are 80% hedged already for 2011. With upside we are already at $1.4 billion cash flow for 2011, ramping up to $1.6 billion. And by the time we reach our 60 rigs in 2012, 2013 we will be clipping along at $2 billion plus a year cash flow. 18% compounded growth rate in cash flow per share.

Slide number seven. Obviously we got significant Spraberry and Eagle Ford, combining that with the Barnett Combo play where we have several hundred locations. The Company now has over 23,000 drilling locations in low-risk drilling, and 21,000 of those are in liquids-rich areas. Our focus is to accelerate those, which we are doing, climbing up to the 60 rigs.

And finally on slide number eight, obviously we have a tremendous inventory, as I mentioned, with over 23,000 drilling locations, most of them liquids-rich. This Reliance transaction with the Eagle Ford JV, obviously allows us to accelerate significantly, taking Eagle Ford up to our net share about 100,000 barrels a day over the next several years. We are accelerating Spraberry, all focused drilling activity in the Spraberry Field. This asset will be climbing up to over 100,000 barrels a day over the next several years. Just focused on the next three years, '11 to '13, delivering 15% plus compounded annual growth rate. Cash flow is going to double by 2013. We will be spending within our cash flow, and obviously we are pretty well protected through 2012, and starting to layering on 2013.

Let me now turn it over to Tim to go over more details of our assets.

Thanks, Scott.

As you have already mentioned, and I think we are all pleased to say, that we are well on our way to executing our drilling ramp-up across the Company. And you can see that in the first slide, slide nine, related to the Spraberry oil drilling campaign. Production was up 4% compared to the first quarter, which is right on target. We drilled about 193 wells so far through the second quarter. That puts us right on schedule to complete a 440 well campaign for the full year 2010. We are running the 20 rigs Scott mentioned, heading towards approximately 30 by year-end. And that puts us in good position to be well on the way to achieving our plan for 440 wells this year, 700 next year in 2011.

One of the most significant new developments you'll find in these slides, is daily we are accumulating related to incremental production reserves from deepening some of the drilling we have done into the lower Wolfcamp and into the deeper Strawn. I'll talk more about that in a few minutes on a subsequent slide, but there is a very significant new piece of data that you'll find in our talks today. Returns continue to be very strong. Of course our average well costs are going up somewhat as we deepen the wells, towards the deeper Wolfcamp and the Strawn, but I think there is excellent economics that are attributable to that increase in costs. The waterflood project is essentially done when it comes to drilling both producers and injectors. We are in the process of establishing baseline production for the waterflood. We will be injecting water here in the third quarter, shortly. And then we expect a response some six months later, anticipate first oil response sometime first half of 2011.

Slide 10 is a little bit more detailed regarding this lower Wolfcamp and Strawn expansion. Many of the wells we have been drilling this year have tested the lower Wolfcamp potential. Of course a lot of the wells we have drilled in the past were drilled in the upper and middle Wolfcamp. But we are now testing the lower Wolfcamp and have found that it is providing significant incremental early production. In fact, of nine wells we tested recently, it added about 25 to 45 BOE per day in terms of early production. And that's important because the traditional Spraberry completion, the traditional zones, tend to yield early production rates of more like 60 barrels a day. And what we found is, after a lot of work by our geo-scientists that the lower Wolfcamp has potential essentially across 100% of our acreage. And so it has a very significant potential in terms of its future contribution for overall reserves in the field.

We are going to be drilling two horizontal Wolfcamp wells actually in the third and fourth quarter upcoming as well. Those will be interesting to see, whether horizontal applications add incremental reserves in the Wolfcamp areas. What's really important I think to add also, is the information we are now gleaning regarding Stawn potential. Interestingly, we drilled two wells that tested Strawn only, recently and had first month production rates of about 70 barrels a day just from the Strawn. So again, comparing that to traditional zones, this is a very substantial piece of information that leads us to the conclusion that there is substantial Strawn potential across certain areas of the field. In fact, other wells, where we added Strawn and lower Wolfcamp to our typical completions had first month production averaging 125 barrels oil equivalent per day.

Of course, this adds additional costs, as I mentioned before, and additional drilling footage. But the fact is I believe it's going to be a very significant increment to both production and reserves. We see the Strawn being productive and having potential across some 30% to 40% plus of our acreage position. So this is something to watch. We have yet to really increment our tight curves regarding overall Spraberry drilling, to incorporate deeper Wolfcamp and Strawn. We will be doing that after we have several more months of production testing. Needless to say this is very significant news, and we are very excited about the potential that it will generate in terms of incremental reserves in production in a field that is simply getting bigger by virtue of our activity.

Slide 11. After all, Spraberry continues to be a margin play and as Scott has alluded to, we have got a strong hedge position. And we have coupled that with several measures to control costs, essentially to preserve margins. Very similar to what we have done in our Raton model, where we are probably the most extensive user and we have the most extensive focus among most of these independents on vertical integration. Toward that end we are expanding the ownership of our own frac fleets. As we've mentioned before, we have one of our frac fleets, which is down from Raton, operating in the field. And now we are up to three addition frac fleets, having been ordered and under construction for delivery over the next several quarters. In association with that we are also building significant number of new frac tanks. Where we are going of course is a very significant increase in self-reliance when it comes to fracking wells looking forward.

And toward that end we have sand supply contracts in place for the next several years. As we mentioned before also, all of our tubulars and pumping unit orders are in place through next year and, in fact, we are beginning to consider the extensions of those contracts into 2012 as well. Today we have six of our own rigs operating in the field, and we will have six remaining -- or six additional rigs in the field by the ends of this year. So we will have 12 rigs running out of that 30 that we mentioned from the year end 2010. We also have significant other equipment that we are utilizing and essentially extending the same concept of vertical integration throughout the field operations. Essentially, where we are heading is to provide about 30% to 60% of our own requirements, in terms of services, once we get to that 40 rig, 1000 well campaign 2012. And that range, of course, depends on the nature of the service, and the availability of alternatives and particularly how much do we think we are doing with cost creep in every significant category. Ultimately, what we are doing is taking very significant strides, and aggressive strides, to mitigate cost creep in a field which is highly dependent upon margin for its returns.

Slide 12 then shows where we are going in terms of Spraberry production rates. We are seeing the exact ramp-up you would expect by virtue of increasing the drilling and the results are so far on target. 32,000 BOE per day in the second quarter. This field is very predictable and gives us a lot of confidence looking forward that the trajectory of production you are looking at on slide 12 in fact is easily doable. Actually, perhaps we could say that it is conservative if you start factoring in deeper Wolfcamp and Strawn. But essentially, it's the case today that we are prepared to execute on our 2011 program, as we speak, 700 wells even today. And looking forward 1000 wells look easily doable for 2012.

I'm going to turn now on slide 13 to our Eagle Ford Shale development. We have five rigs running in the field, as shown on the map here, in three different counties. We are actually showing some very steady improvement in terms of reducing well costs and days drilling on these wells to 30 days or less. And that's what you expect the further we continue down the learning curve, in terms of performance on drilling. We still have only five wells producing in the field. Of course by virtue of drilling we have done since our announcement of the joint venture, we have additional wells that have been completed and awaiting completion. There are three wells today that are now awaiting central gathering and processing facility construction that will be put online in the fourth quarter. And then three additional wells that are awaiting completion. They will also be put on line in the fourth quarter.

So fourth quarter is where you expect a significant bump in production when those CGPs are put in place. Further to the drilling campaign, as Scott already mentioned, we have the two additional rigs contracted to take us to seven rigs by the end of the year. Another significant development of this quarter, is the fact that we now have, in fact, purchased our own Company-owned frac fleet for south Texas, which will be operational in the second quarter next year, using much the same model as we have used in the Permian Basin. And in fact, we have contracted the vast majority of the profit we will need for both the remaining part of this year and 2011. In addition, we are taking a step to lock up a contracted third party frac fleet commencing the first of the year, for two years. To guarantee our ability to complete our wells on a timely basis in the next couple of years.

Midstream construction is underway. As we mentioned before, we are spending about $50 million net to Pioneer, in the second half of this year, to begin the process of midstream construction and tying in wells. We are planning on having several CGPs in place. In fact, five by the end of this year. We have construction going on on several today. We have two of the central gathering and processing facilities purchased in terms of the leasehold or land, and three under negotiation. We are laying about 50 miles worth of pipeline as we speak. And two of the CGPs are under construction. One is expected to be done mid-September. The next mid-October. And then three during November, December. So this is the key to ramping-up production looking forward. We are in the process of negotiating downstream third party agreements with several parties. This will, of course, be the way in which we deal with liquids-rich gas, stripping out the NGLs and also selling condensate to oil-related markets. Those negotiations, hopefully, will be concluded shortly. And we'll talk more about that perhaps in the next quarter call.

Slide 14, then shows the net impact of Eagle Ford production. As expected, production was relatively limited in the second quarter while we await those CGPs being put in place so as to allow well hookups. You can see our production bumps pretty significantly in fourth quarter, but even significantly more radically as you look forward, as we ramp-up the drilling and begin the process of putting the construction in place. We have a great deal of confidence in our ability to execute on this plan. And you can see, with us having seven rigs at the end of this year, it will be no problem to average 10 rigs in 2011 so as to drill 70 wells, and then 14 rigs in 2012 drilling 120 wells. It will be something that we can easily achieve.

Slide 15 then, just a summary slide we use during the discussion surrounding the joint venture. A significant benefit of this joint venture, of course, is the fact that if you combine the up-front cash with the carries associated with drilling going forward, these two yield a positive cash flow scenario for Pioneer throughout the life of the JV. And it is a significant contributor to our overall corporate objective to maintain the free cash flow model that Scott referenced. So, we are very pleased to have this joint venture in place, and as I said, I think it will be a significant, positive contributor to our net cash positioning going forward.

Finally on slide 16 related to Eagle Ford, there has been a lot of discussion surrounding the effect, potentially of Eagle Ford shale NGLs on US NGL markets, and for that matter, worldwide NGL markets. This slide is intended to give you a feel for the returns of the project with various percentages in terms of NGL price compared to WTI. So, for instance, if we are dealing with a high yield condensate -- high yield well, of say 200 barrels per million cubic feet, and we were in the area of 50% NGL compared to WTI prices, we would be generating an 85% rate of return. In the lower condensate yield areas that would be more of about 60 barrels per million. A 60% return. Importantly, even if we were to drop NGLs down to 25% of WTI, you can see the rates of return at 70% and 40% in each case, are very stellar. And it's owing to the fact that oil and condensate in this project is carrying the day.

Of course it is very unlikely you get down to such a low percentage of WTI, simply because even if you have a case where ethane is 50% of the NGL stream, you have 50% of the stream which is going to be tied more to WTI-oriented prices. In addition, the lower that ethane prices go, the more likely that they simply will be rejected and left in the gas stream, meaning you have a floor at natural gas prices for the equivalent ethane price. This is not a scenario that makes much sense but nonetheless we want to show that the Eagle Ford shale economics are very resilient, even with low NGL pricing.

Slide 17 is a slide regarding our entry into the Barnett shale Combo play. We are a relatively new entrant into the play, but I think an aggressive one. And we've taken pretty aggressive steps with our 43,000 net acre position in North Texas, specifically in Northern Wise and Southern Montague counties. We have today, by virtue of that acreage, put in place a position where we could drill some 400 wells in this play. We also have acquired significant 3D seismic and will actually be doing some more. Our first rig will be in the field here next month. We are planning to drill about eight wells the remaining part of this year, and internally we are using a gross EUR of about 320,000 BOE.

You'll find if you check some of the leading competition in this play, that they are using more in the neighborhood of 430,000 BOE, but our objective here of course is to be conservative. But we anticipate we are going to be very competitive in the play, as our per well costs are in the neighborhood of $2.8 million, in terms of what we expect for the upcoming drilling campaign. So strong rates of return. And we will be ramping this project up. The way we look at this is as another significant oil-related investment opportunity for the Company, just like we see the Permian Basin and the Eagle Ford shale.

I'm going to stop there. Of course, Scott mentioned a couple of commentaries surrounding Tunisia, where we had a couple of successful wells that look very interesting. I think we will plan to talk more about those in the future as we have detailed test results. Alaska, suffice it to say, we have continued successful drilling program. Things are going very well there, as well. With that, I'm going to pass it to Rich, for his review of the financials for the second quarter and his outlook for the third quarter.

Thanks, Tim.

Turning to Slide 18. Net income attributable to common stockholders was $168 million or $1.41 per share that we reported. That did include, as Scott mentioned, mark-to-market derivative gains of $84 million or $0.71. And $33 million of unusual items that were gain items for the most part, or $0.27. The most significant of the unusual items was the receipt, as Scott mentioned, from the MMS of $35 million pretax, related to interest on the Gulf of Mexico excess royalty refund that we got earlier this year of $119 million. In addition we got $14 million, pretax, of Alaskan PPT credits and this reflected in there as well. So adjusting for those items, we are at $51 million or $0.43 per share.

Looking at the bottom of slide 18 and how we performed relative to our Q2 guidance, you'll see that our guidance -- our results were within -- were on the positive side of guidance on all the measures. We mentioned earlier we did have a production shortfall in terms of it being at 113,500 BOEs per day. 1500 barrels that we had lost because of unscheduled downtime, and so we would have been a little bit higher had we had those barrels. On the cost side of the business, I think the important message here is that the asset teams continue to do a great job of controlling our cost structure. If you look at our cost structure, we remain significantly lower than the average of our peers, particularly our oil focused peers. And very competitive with our gas focused companies.

Turning to slide 19 and price realizations. You can see in the green bars there that oil price is relatively flat quarter-on-quarter. I think the message more is on NGL prices than gas prices. If you look at NGL prices, our realizations were down 18% from the first quarter. This is really the seasonal impact of coming out of the winter months, where we see ethane was down 25% quarter-on-quarter, and propane was down 13% quarter-on-quarter. Looking at gas prices, gas prices, relative to the first quarter, were down 23% to $4.10, really reflecting the mismatch that we see of supply versus demand, and particularly the low economic growth projected for the US which is having -- hurting gas prices.

Turning to slide 20, production costs for the second quarter were $11.88, up $0.53 or 5% from the first quarter. This really reflects the reduction in our natural gas processing margins that we get from third party gas that we process through our mainly our mid-Continent plants, as a result of the lower NGL and gas prices, since we keep a percentage of their production. In addition, base LOE was up $0.53 per BOE. Really just increased maintenance activity, and this was offset by lower workover activity, lower taxes, and slightly lower transportation costs.

Turning to slide 21, focus on third quarter guidance. You'll see our daily production guidance is 113,000 to 116,000 BOE's per day. That's relatively flat with the second quarter, when you adjust for the down time for the unplanned pipeline curtailments in Alaska, and then for the fact that we sold basically 1000 BOE's a day of Eagle Ford production in conjunction with joint venture. That's how we get to this guidance level. As both Tim and Scott mentioned, really the fourth quarter is where you are going to see the infrastructure coming into Eagle Ford, the additional production from Tunisia, continued ramp-up from Spraberry, and that will be where you see the big production ramp-up. The other items here are very consistent with prior quarters, so I won't go through each one individually. I just wanted those to be there relative to where we see the third quarter coming out.

So why don't I stop there. And we'll open up the call for questions.

Thank you.

(Operator Instructions)

We will take our first question from Dave Kistler with Simmons & Co.

Good morning. Hoping onto the production guidance for a second, at about 113,500 barrels of oil per day, 1,500 down as result of various downtime. Then looking at two incremental thousand barrels coming from Eagle Ford in Q4, feels like you guys are positioned to keep pushing that guidance higher, pretty easily. Am I missing something? That's obviously just hitting a few small pieces and there's obviously a lot more activity in Spraberry, etcetera?

Yes, as you can see, our big ramp-up is going to be fourth quarter and first quarter of next year. Obviously, we are being conservative. You can always have unplanned downtime, but we do see significant ramp-up over the next several years. With Spraberry over-performing, obviously over time with more history from the Strawn and the lower Wolfcamp zones. We hope to update and increase guidance, obviously with the Spraberry program. Eagle Ford program is pretty much what it is, we have it fairly well modeled. Barnett obviously will increase with time by going up to four rigs. It's got a significant ramp-up over the next several years. Obviously we hope -- it is always nice when you have positive results where you can increase guidance.

But right now, we see it primarily -- as I had mentioned, you have got to realize only six, seven months ago we were at five rigs in the company. Today we are a little bit -- we are at 27, 28 rigs. We are jumping to 40 rigs by the end of the year. It just takes time to bring the activity on and execute. So we are confident we are going to do it.

The trend line is certainly almost exponential as we start -- as we continue moving forward, is basically what I'm getting at.

Obviously.

I realize that next quarter is a challenge -- not a challenge, but isn't going to have the full impact of a few of these things yet.

That's right. As I mentioned on that one slide, it only took 20 rigs for the company to grow 10% from our old base. That's even before Eagle Ford. Now we are going from 20 rigs, from '06 to '09, to a 60 rig clip from a company standpoint, from '11 through '13.

Then switching over -- that's helpful. But switching over to the horizontals in the Wolfcamp. Can you talk a little bit about the length of laterals there? And just conceptually, obviously it is more densely down spaced in the top zones at Spraberry, and the bottom zones not as densely down state. Would this be a way to more efficiently be able to hit bottom parts of the zone, and getting there and trying to optimize your vertical wells?

Dave, I think the answer is -- of course, we won't really know until we drill the wells, but the answer to your first question is, it will be at about 4000-foot laterals. The targeted zones today as we envision it would be probably one well targeting the middle Wolfcamp, and perhaps one targeting the deeper Wolfcamp. But the whole objectives of these are just like any other horizontal drilling campaign. That is we are looking for a material buff in EUR and production that offsets what is a pretty significant increase in the cost of the wells. And I guess the proof is in the pudding. We will get back to you when we fine out the results.

Okay. That's very helpful. I'll let somebody else jump on.

Thank you. Next with Goldman Sachs, we will hear from Brian Singer.

Are you on, Brian? You got a question, Brian?

Brian if you are using a speaker phone, please pick up your handset and press your mute you function. Hearing no response, we will move to Michael Hall with Wells Fargo.

Thanks. Good morning.

Hi Michael, how are you doing?

Good. Congrats on a solid quarter.

Just wanted to jump on one thing in the Eagle Ford as to the dedicated third-party frac fleet. With that, and your own company-owned frac fleet, how much of the total frac needs will be covered by those in 2011, and then maybe thinking a little further out as well?

Yes, of course. The way to think about frac fleets in south Texas is each can frac about 40 wells a year. And such that when we have two working, we can frac about 80 wells. So what that points to is with a 70 well campaign in 2011, it is easily the case that we will be fracking all of our own wells, with both our own rig and a third-party fleet. Looking forward to 140 wells, we'll have to make a decision what to do there. It is not out of the realm of possibility that we would add an additional fleet to take the completion count higher with our own completion, completion equipment.

Okay. Great. And then, if I may still, I like that Slide 16, very helpful I think as it relates to the NGL price impact on Eagle Ford economics. Condensate. Just to be clear, is there any reason to think that condensate prices could decouple at all from their relationship to WTI, or do you think that's pretty robust pricing market?

Mike, I don't think -- I know there is more refining switch to sour crude on the gulf coast in the last 10 years, but right now with Spraberry crude, at Cushing of getting WTI, right now we are getting somewhere between 250 and 350, including transportation, less WTI. I don't see that -- there is still a need to blend with Canadian crude and other sour crudes to help improve the price, and so there is still fairly high demand for -- now five years from now, if this country adds a half a million to a million barrels of condensate, from all these plays, you may have a different issue. But right now I don't see any problems.

Okay. That's helpful. Thank you. One last line of questioning. Barnett Shale. How much do you have sunk in the liquids-rich area now? And how did you go about selecting that particular acreage?

I think the most important thing is that based on the -- what we have seen from a couple of the competitors, I think you know who they are, we have studied it. Being south of them over the last two or three years, we decided with oil prices trading at 18 to 1, that it is something we ought to look at, and we were surprised about how cheap the acreage is. It's running about 1/10 the cost of what Eagle Ford acreage is. So you can get the same returns, less competitive. Instead of having 30 people competing with you in the Eagle Ford, you would probably have one or two in this play.

So we decided to move into the play early, about 18 months ago, and as Tim said, we built up to 43,000 acres. We can't give out our targeted range, but we are continuing to buy. We will have several hundred locations. And it will be as good of returns as Spraberry or as Eagle Ford. So it is nice to have a third play that we can ramp up significant production over time.

And so, just to try and get a little more granular. Is it $50 million sunk at this point into the project? Just trying to get a little better feel for it.

I can give you acreage -- you can -- you know what Eagle Ford -- I gave you a rounding area. You know what Eagle Ford is going for, top end say at a 10th. So multiply that by maybe a little less than that for 43,000 acres or so.

Okay. Great. I Appreciate it. Thanks, guys.

And next we will hear from Brian Singer with Goldman Sachs.

Thanks. Good morning. Can you hear me better this time?

Yes Brian.

You were whistling last time. Not sure what you were doing there.

Fantastic. Thanks a lot. Apologies earlier. Going back to Spraberry and Wolfcamp. Can you just talk about the timing of the production trajectory as we go into next year? Is it fair to characterize that 20 rig program as giving you a little bit closer to about 1000 barrels per day growth per quarter, and that based on your guidance, 30 rig or 25, 30 rig program will get you more of 1500 barrels a day to 2000 barrels a day growth per quarter? And maybe just comment on the expected improvement in productivity per rig as you drill deeper.

Yes, I think the way to couch it is, first of all, again, as I mentioned earlier in the commentary, it is difficult to say definitively today until we get some more wells drilled. But as we pointed to you on Slide 10, we think that we are dealing with wells that will incrementally add some 20% to 30% at a minimum of EURs, and I think that will translate directly into production. The production curves that you see on Slide 12, that show a little bit of granularity on Permian growth, do not include any effects from that. This was your baseline theme, upper, lower Spraberry completions, maybe a little upper Wolfcamp. What that means is, it is potential that we would have some 20% to 30% upside just in relation to looking at that graph. Now, we will have to see, but at there point in time, I would say we are being very conservative.

Great. Thanks. And then, in Alaska, do you have any updated thoughts on where you think you can get production to in the next couple of quarters? And then how long you can hold production at that level?

Yes, Brian, we are drilling -- we are just finishing an important well now that is a dual lateral in the Nuiqsut. It will be coming on and testing over the next several weeks. We are probably most likely -- our successful Moraine test, that we announced about six months ago, it has been flat right now at 600 barrels a day, with no decline. So obviously we are going to do some more drilling this coming winter with that. So obviously we see -- we still continue to see a couple thousand -- what I tell most people with our investment -- total production increasing about 2000 barrels a day per year. There is upside to that if we see some benefits from this Moraine drilling we are going to do this coming winter, and do some more testing, and also with a water injection well in that regard too.

So right now, 2000 barrels per day per year gross production in Alaska. Say we are at 12 now roughly, 11 to 12. So adding a couple thousand barrels a day per year.

Great, thanks. And lastly, given the growth coming out of Spraberry, Eagle Ford, etcetera, how are you thinking about the strategic nature of the various opportunities you have in West Africa, and could those be candidates for asset sales down the road?

We do not have anything in West Africa. You probably meant North Africa.

Africa overall.

Oh, Africa overall, yes. Our South Africa project is fairly flat. We are just going to produce it out to 2013. There is a great -- we got two people managing it, three people managing it. High margin there. Obviously we are getting much higher gas prices than we are in the US, and we get a great price for our condensate. It will produce out to 2013 and possibly extending the reserves could last another five years past that. Maybe eight. So we could have the possibility of an extension. But right now, we are just going to produce that project out.

In North Africa, in Tunisia, it is a question of -- in regard to the three well program. We were drilling these three wells. Then at some point in time make a strategic decision, whether or not to drill more wells, or do something else with that project. So these three wells so far are very, very positive. So we will come out at some point in time and decide what is there. But this key well that I mentioned, in Anaguid, opens up a no -- whole other fair play -- fairway up in, going north, obviously has got us excited with potential. So it is really just a question, do we keep it going? Or do we take that and divest of it at some point in time and redeploy that capital into our three key assets?

Great. Thank you.

Thank you. Next we will hear from Leo Mariani with RBC Capital.

Good morning, guys. Quick follow-up question on the Barnett Combo. Obviously you're picking up acreage. You are going to drill some of your initial wells here soon. You want to ramp up it to four rigs. What gives you the confidence without any well results to want to ramp that program next year? What type of well control do you have in and around your acreage that convinces you that you've got something there.

It is simple. A combination of 3D, offset acreage right next to the two plain players in the area. Both Devon and EOG. And have really been studying their history over the last several years, has got us our confidence level. So a combination of 3D, seismic, the ability to be able to frac wells, and not move into water at all, based in results we have seen from offset operators, has got us the confidence level and history from both of those two operators.

Okay. I guess jumping over to Tunisia here. I know you guys have some non-op wells also that you're participating in. When do you expect to see any results there?

Yes, we have had success with that drilling. Production should be on shortly. In addition, we don't have a Tunisia slide this time, but there has also been some significant discoveries on what we call the BEK block, to the south by OMV. OMV is continuing -- I think they have announced seven or eight discoveries now, to date. High gas and condensate wells to BEK. We just completed our 3D seismic. We will be reviewing that here shortly. On BEK we see huge upside potential. Obviously, in BEK in those blocks also. So we will have more data over time with both Anaguid, and also BEK, and the recent results we drill with ENI.

Okay. And what's your interest in the BEK block there?

It is 40%, but the government has the right to come back in on successes for 50%. So 40% initially, down to 20%.

Okay. I guess, in terms of your program here, obviously you've picking up a lot of your own service equipment it looks like. You know in the course of the next -- I guess year, year and a half, any kind of estimate as to what the capital costs are going to be to you folks from that additional equipment? The rigs and frac crews and frac tanks and everything?

Leo, it is Tim. Just to give you just a frame of reference. The Permian Basin units I was speaking of, that is the frac fleets we will be adding over the next several quarters, those run about $18 million each. Something like that. Of course in the Eagle Ford Shale, we need more horsepower. Something like two times the horsepower. Those rigs -- that frac is going to run between $35 and $40 million. So, overall you are probably in the $100 million range, in terms of overall cash going out the door for vertical integration.

Okay. And does that include the rigs as well, Tim?

Yes, that includes the rigs. But the rigs -- some of the rigs of course were purchased last year.

Okay. I guess jumping over to the Eagle Ford, it sounds like you guys have three new wells there that you haven't put onto production yet. Do you have production tests on those three new wells at all?

Yes. And they look as good as our prior wells.

Okay. Are those in oil and in condensate zones, or dry gas zones, or kind of all across your acreage?

Those are in the liquids rich zone. That's where we are focusing the drilling.

Okay. So roughly what percent of your drilling do you think is going to be in the liquids-rich zone next year, as opposed to more dry gas roughly?

I want to say at least 90% will be in liquids-rich areas based on current economics.

Okay. Thanks, guys.

And our next question comes from Brian Corales with Howard Weil.

Hello guys. Just a couple follow-ons on the service side. Are you all planning to add addition services to the Eagle Ford acreage -- or to -- for the Eagle Ford?

Well, of course at this point in time the one thing we have added is the frac fleet I mentioned, which actually has coil tubing associated with it, that will come in and be in service second quarter next year. The rest of the services are under consideration. Those are always under evaluation. We think they have very fast payouts.

For instance, we think that our frac fleet down there has essentially a one-year pay out, because of the costs having been going up significantly down there, and so we will evaluate all the different services to be provided in the area. One thing we are dealing with in the Eagle Ford, we don't deal with in the Spraberry, is quite an extensive geographical area that this play covers. As opposed to Permian, we are all pretty much centralized in the Permian Basin. So it's not quite as easy to provide all your own services.

But this model has worked exceedingly well in our Raton operation, it's working very well in Permian. So I don't see why it wouldn't apply in Eagle Ford in an accelerated fashion as well.

Has the service environment gotten improved? Do you think other operators are going to follow this same kind of path?

I can't speak for other operators. I think services there sort of are what they are. It is a very frothy situation in the Eagle Ford shale. Accordingly, you can make the case that there is going to be quite a backup, in terms of wells waiting on completion because of that. Of course, we are putting ourselves ahead of that curve by, on the one hand having our own frac fleet, and also contracting a frac fleet for the next two years. But suffice it to say, the result has been also a significant increase in costs. So the result has been some delays in terms of getting wells fracked in the industry, sometimes as long as a couple months. And what we are trying to do is obviate all of that by having our own fleets in place.

Right. And two more questions. One on Tunisia. I know other operators have talked about pursuing some shale opportunities there. Is that something you all have looked at, or evaluated? And also maybe just your general thoughts on the NGL market and what you are doing to maximize price there?

Brian, there is a primary zone called the [Tenezev] shale zone that some of our competitors are looking at seriously. We have taken cores recently and looked at it. Looking at testing it also. So it is very, very early in the stage. Obviously it is an important area, an important zone for upside in Tunisia. But to date there has not been -- to my knowledge there has not been any horizontal drilling, or there is no horizontal fracture stimulation equipment set up in Tunisia, which is one of the issues. Hoping to take that to the next step, but right now it is all in the study phase.

Regarding your NGL question, I think our goal is to make sure, whether it is Spraberry, Eagle Ford or mid-continent. With all -- the amount of NGLs -- our NGLs will probably double over the next several years. And due to drilling in these rich plays to make sure that we have the ability to fractionate it, that it gets cracked and gets shipped out. I don't see a big problem for the next two years, in regards to this industry, but two to five years you may have a significant problem in regards to the question of whether or not the petro-chem industry will come back. Industrial demand will come back over time. We lost about 5 BCF a day from 2000 to about 2008. Whether or not that will come back and then what happens to the export market. Export market has picked up significantly, recently going into Mexico and also to South America. And we don't have a good feel on how much this country will be able to export, in regard to ethane, ethylene, propane, polypropylene and so on. Those are the two key ingredients. I don't think anybody knows. The market, the ethane market and propane markets in contango right now. So, it is decent prices. But usually if you look at it in the winter months we see spikes, so it is hard to sit there and lock in a price today based on potential upsides we have seen in this past winter. Generally you look at past winters. You do get a bump in ethane and also a bump in propane plus. So our goal is to protect ourselves to make sure we can get our product fractionated, as I mentioned, and also sold.

This may be kind of an elementary question, but when you go out and hedge the NGL market, you have to hedge each individual product?

You can or you can take the components that are tied to gas, which is like ethane and you can hedge natural gas, if you like the natural gas price. Or you can take the components from propane, butane, pentanes plus, which pretty much correlate with crude, and you can hedge crude. So you can do one of both ways.

Okay. All right, guys. Thank you.

And next with Wells Fargo we will hear from Michael Hall.

Hi. Thanks for the follow-up. Just wanted to circle back on the frac fleet addition -- or I should say the long-term contract in the Eagle Ford. Any concern that, like you said Tim, it's kind of frothy on frac prices there, that this is the wrong time to be locking in long-term contracts? How did you protect yourself in the negotiations there regarding that?

Well, we have terms we think that are reflective of the current market. But, that said, we have a significant campaign in our JV to drill wells, and this is just one of the ingredients to get that done, complete the wells that we are going to be drilling with a large campaign associated with our Eagle Ford JV. I will tell you I think we can complete these wells cheaper from our own frac fleet, probably to the tune of $1 million cheaper, by virtue of using our own equipment.

Okay. But in terms of the third-party dedicated fleet, was that priced at current market levels then, I would assume?

Essentially current market levels. That's right.

So maybe give up a little pricing in order to mitigate operational risk down the road? Is that fair to think about it that way?

Yes, I think you look at it and say the market for these services kind of is what it is. That said it could easily get more frothy as you look at the -- what I mentioned to be an outlook that we are looking at, which is to say potentially you have got a significant number of wells in the overall play which remain uncompleted, if you look at the number of rigs that are running. I think there is probably upside, potentially, in some of the costs there, as opposed to downside today.

Fair enough. Thank you very much for the follow-up.

And next we will hear from David Heikkenen with Tudor, Pickering & Holt.

Thanks guys. Just want to talk about how the organization is performing and responding to the increased activity. Do you see any pinch points or stress points in the organization as you ramp-up at the current level, or as you look forward over the next year? What should we be watching for or listening for?

Yes, David. As I mentioned, we have already contracted and got the people to get up to 40 rigs by the end of the year. So we are at 27 now, going to 40 rigs. We are in the process of contracting an extra 20 rigs to go to 60. We have got all the people in place. And we got separate teams now, as we had mentioned several months ago, in Eagle Ford. A dedicated team strictly at Eagle Ford, versus other south Texas assets. Spraberry is already -- we have had a program where actually I'm hiring some ex-military people, significant amounts -- a program that came to us about a year ago. Some of our people got involved in that. And that has worked very, very well. People coming out of the military, in regard to the Midland-Odessa area.

Obviously on the service side, what's nice when you start up the service frac crews, we've see no issues of hiring people because of what's happening -- we do have to be careful of rating -- we had third-party services, not to rate those, but obviously we are going after other companies that we are not using. Those people call us up, as soon as we get a frac crew up, and we have hundreds of applicants calling us up because they would rather work for an oil and gas company versus a service company. So obviously there is a lot of pluses being an E&P company and being the biggest operator in the Permian Basin. So we see no issue there. And the same thing is, we will eventually be one of the biggest operators in south Texas with our Eagle Ford fleet. Those are the two areas where the pressure is. We have got the staff, the people and really see no issues. Tim, you got any?

The only thing I'd add is, David, we were running 30 rigs before the downturn, and we didn't let any people go. So that was a fortuitous decision and looking to where we are today -- that is we have a staff built for a high rate of drilling campaign and that's been a very fortunate situation for us.

And then on the joint venture process, is reliance succumbing any employees or engineers to learn through the process, or is it purely financial at this point?

They will, eventually succumb people into our offices here in Las Gallinas, and we anticipate that number will be approximately 10. Today they do not have anyone here. ***Auditing Terminated after 1 hour of audio.***

Okay. Just curious how that works. And then, as you think about -- just on one detail, are you leasing in any other areas as you think about the free cash generation over the next two, three years? Talked about Barnett Combo as a growth area. Is there anything else that is kind of on the horizon that you would be willing to talk about?

No. With 23,000 drilling locations, with 21,000 of those in oil-rich areas, we see no need to build up our inventory anywhere else, at this point in time.

How does the 400 locations and Barnett Combo really fit into that strategy?

What's amazing is that it actually -- the asset gets up to somewhere between 35,000 and 50,000 barrels a day. Over time by running one to four --six rigs -- we ramp it up to six rigs, the asset climbs significantly. So it's sort of like Eagle Ford but about half the size, and obviously we are keeping 100% of this versus doing a JV.

Okay.

So it essentially gets half the impact by keeping 100% of it. It allows us to get up to about half the levels that Eagle Ford would get. And we have plenty of -- that's where some of the excess cash flow is going to be going into, into that play.

All right. Thanks, guys.

And our next question comes from Robert Christensen with Buckingham Research Group. Robert, your line is open.

Bob, you got any questions?

(Operator Instructions) Hearing no response, we move to Richard Tullis with Capital One Investments.

Thank you. Good morning. Moving back over to the lower Wolfcamp, Strawn economics. How much did you estimate the well costs would go up on a gross basis?

I think it is about $100,000.

And that's just one stage frac?

Yes, that's right.

Additional. Okay. How many locations do you estimate you could have there?

Well, I think it couched -- in the Permian Basin we have 20,000 locations to drill, if you start getting into 20 acre locations. You have to look at it more how -- what is the aerial extent of the Strawn in terms of potential? And today we say it's about 30% or 40% of our acreage. Today we have roughly 900,000 acres under lease in the Permian Basin. So it is a substantial amount of potential that we are talking about.

Okay. Looking at the Eagle Ford JV, if I remember correctly, reliance has the option to perform some drilling completion operations of their own starting next year. What's the plan there at this point?

You're correct, they do have the right to do so. We are not aware of any of their -- of a plan on their part to commence drilling next year at this time.

Okay. I guess most of the focus for the acreage acquisitions is on the Barnett Combo at this point. Are you seeing any other opportunities that you might pursue near term?

No, not at this time.

Okay. And then just finally in Tunisia, what's the time line for bringing on the wells that were just recently drilled?

We will get into more detail on that as we -- all three, but it will be -- most of it will come on in fourth quarter.

Okay. Alright, that's all for me. Thanks very much.

And our final question comes from Ben [Zipolfa] with IHS.

Hi. Yes, just on the lower Wolfcamp and the deeper Strawn. The 100,000 extra dollars to drill it. I mean, it seems like it is quite a bit deeper, than if you go from the base of the dean. I'm just looking at your picture here on page 10, all the way to the Strawn, and I was just surprised that it would only cost only an extra $100,000 to go all the way from the base of the dean all the way down to the Strawn.

I'm talking about the amount to deepen the well from the lower Wolfcamp.

Oh, all right. And could you give us -- and typically you talk about, about $1 million per well to complete -- drill and complete a typical Spraberry well. I was just wondering, how much above that it would be if you were to drill down to the lower Wolfcamp and the Strawn and complete those as well?

We talked about that earlier in our commentary. It was a case that our average well costs is more like $1 million and we were just completing the wells in the traditional way, that is in the typical Spraberry and Dean formations and perhaps the upper most of the Wolfcamp. Now with the deepening of the wells, particularly into the deeper Wolfcamp and Strawn, we see those costs increasing just by virtue of the deepening of the wells. And they are averaging now $1.1 million to $1.2 million.

Okay. And what were the main factors that prevented the deeper zones from being economically developed, in the past even when we had $100 plus oil?

I don't think there were any limitations, other than to stay we put an outstanding team of geo-scientists and engineers on the project evaluating what we have under lease in the Permian Basin, and we owe a lot to them for uncovering a lot of these angles that essentially just add up to increasing recoveries in a huge field. And so as we put more science into this it you can expect that our results will improve.

Okay. And what limits the prospectivity of the Strawn that you've estimated now to be on 30% to 40% of your acreage? What geological factors are a determinant in that 30% to 40%?

Well, it is just simply the fact it is a carbonate play. It's not ubiquitous, as compared to most of Spraberry play. So you are simply not going to find it's -- it being -- having significant porosity essentially across all of the acreage. Only about 30 to 40% of the acreage. You find the Strawn and the question is, where do you have pay?

Alright. And finally, just for deffered taxes -- I see you gave some for the third quarter. What about the fourth quarter? What might be -- should we consider that the percentages would remain the same in the fourth quarter as -- those two would be the same, third and fourth quarter?

Yes. I would expect them, based on what we said today, with commodity pricing, will be about the same.

All right. Thank you very much.

Thank you. That does conclude the question-and-answer session today. At this time I'll turn the call back over to Mr. Scott Sheffield for any additional or closing remarks.

Again, thanks. We appreciate everybody listening in. Look forward to the next quarter. Obviously, we will continue to look -- add to rig count, increase, like I said, our rig count up to 40 by the end of the year, and climb that up to 60 by the end of 2011. Thank you.

Thank you. This does conclude our conference. We thank you all for your participation.