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Pioneer Natural Resources (NYSE:PXD)

Q2 2010 Earnings Conference Call

July 29, 2010 11:00 am ET

Executives

Scott Sheffield - Chairman and CEO

Tim Dove - President and COO

Rich Dealy - EVP and CFO

Frank Hopkins - VP of IR

Analysts

Dave Kistler - Simmons & Company

Brian Singer - Goldman Sachs

Leo Mariani - RBC Capital Markets

Brian Corales - Howard Weil

Michael Hall - Wells Fargo

David Heikkinen - Tudor, Pickering, Holt

Richard Tullis - Capital One Investments

Operator

Welcome to the Pioneer Natural Resources Second Quarter Conference Call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer, and Frank Hopkins, 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, 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 news release, on page two of the slide presentation, and in Pioneer's public filings made with the Securities and Exchange Commission.

Please note today's call is being recorded.

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

Frank Hopkins

Good day, everyone, and thank you for joining us. Let me briefly go over the agenda for today's call. Scott's going to be up first. He'll review the financial and operating highlights for the second quarter of 2010, another solid quarter performance from Pioneer. He'll then comment on the company's plans for the remainder of this year and look beyond in the next couple of 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 and after that as usual open up the call for your questions.

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

Scott Sheffield

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 IRS from our deepwater cell several years ago. And in addition 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 unclaimed curtailments and taps up in Alaska.

The pipeline and Mid-Continent gas processing plan downturn roughly about 1,500 barrels a day. We will talk more about it later but obviously we are on track and expect significant production to ramp up in the first 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 strong 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 allows us to accelerate, protect our acreage, more drilling in the Eagle Ford Shale play.

Pioneer field like having the best only plays in the U.S. will be accelerating activity significantly. We are at 25 rigs in those two plays right 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 in production. But I think the most important thing is we have had a discovery in [ENI] block which is over half a 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 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've got two great assets that each one will be climbing up to over 100,000 barrels a day each, both in the Spraberry and Eagle Ford over the next 10 to 12 years.

The fourth quarter, we're 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 CGP, 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've kept that flat. We don't really see increases in our capital between now and the end of the year. We think it's important to have a free cash flow model as we have. Going forward, again, we're 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, in 2006 to 2009, we averaged about 20 rigs to get to 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 in 2011, 2013 we will be at 60 rigs company-wide.

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 upfront cash from the JV of 266 million. Up does include our Deepwater Gulf of Mexico refund of 150 million.

Drilling capital about 960 million spread out primarily among Spraberry, obviously Eagle Ford and Alaska. And 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 will be called a Combo area with strong returns.

That cash flow is pretty well protected. Looking out in other 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 combine that with the Barnett Combo Play with several different 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 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 laying on 2013.

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

Tim Dove

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 this 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 water flood project is essentially done when it comes to drilling both producers and injectors. We are in the process of establishing baseline production for the water flood. We will be injecting water here in the third quarter shortly. And then we expect a response some six months later, anticipating 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 drilled in the past were drilled in the upper and little Wolfcamp, but we are now testing the lower Wolfcamp and have found that it's providing significant incremental early production. In fact, of nine wells we tested recently, they had 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 geoscientists, that the lower Wolfcamp has potential essentially across 100% of our acreage. 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 that are upcoming as well. Those will be interesting to see with a horizontal applications and incremental reserves in the Wolfcamp areas. What's really important I think to add also is the information we are now gleaning regarding Strawn potential.

Interestingly we drilled two wells that tested Strawn only recently and as first, 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 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 at first month production averaging 125 barrels oil equivalent per day. And of course this adds additional costs as I mentioned before and additional drilling footage, but the fact is I believe its going to be a very significant increment to both production and reserves.

We see this 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. But 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 and production in a field that's simply getting bigger by virtue of our activity.

Slide 11, after all Spraberry continues to be a margin play and as Scott as 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 user and we have the most extensive focus among most of the independents on vertical integration. And toward that end, we are expanding the ownership of our own frac fleets. As we 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 and self-reliance when it comes to fracing 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 year-end 2010.

We also have significant other equipment that we are utilizing and essentially extending the same concept of integral 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 thousand 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 of significant category.

Ultimately what we are doing is taking very significant strides and aggressive strides to mitigate costs 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'd expect by the 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. The trajectory of production you are looking at on slide 12 in fact is easily doable. Actually perhaps we could say that it's conservative if you start factoring in deeper Wolfcamp and Strawn. But essentially it's the case today that we're 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 very steady improvement in terms of reducing well cost 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 waiting 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 waiting 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. And we got another significant development of this quarter is the fact that we now have, in fact, purchased our own company-owned frac fleet or 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 contracted the vast majority of the profit we are going to 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 years.

Midstream construction is underway. As we mentioned before we are spending 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 will 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 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 we can easily achieve.

Slide 15 then, just a summary slide we used during the discussion surrounding, the joint venture. A significant benefit of this joint venture, of course, is the fact that if you combine the upfront cash with the carries associated with drilling Eagle Ford, 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 U.S. 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 the terms of NGL price compared to WTI. So, for instance, if we are dealing with a high yield condensate, a 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'd be generating an 85% rate of return. In the lower condensate yield areas, that would be more of about 60 barrels per billion, a 60% return.

Importantly, even if we were to drop NGLs down to 25% of the 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 condensate in this project is carrying the day. Of course, it's 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. So 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 relatively new entrant into the play, but I think an aggressive one, and we have taken pretty aggressive steps with our 43,000 net acre position in north Texas specifically in Northern wise and southern Monte counties. And we have today by virtue of that acreage put in place a position where we can drill some 400 wells in this play.

We also have acquired significant 3D seismic and we 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 they are using more in the neighborhood of 430,000 BOE, but our objective of course it to be conservative. But we anticipate, we're going to be very competitive with the plays are well cost 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. And the way we look at this is as another significant oil-related investment opportunity for the company, just like we see Permian Basin and Eagle Ford Shale.

So 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 says we have continued successful drilling program. Things are going very well there as well.

So 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.

Rich Dealy

Thanks, Tim. Turning to slide 18, net income attributable to common stockholders was 168 million or $1.41 per share that we reported. It did include as Scott mentioned, mark-to-market derivative gain 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 it is 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 or on the positive side of the guidance on all the measures.

We mentioned earlier we did have a production shortfall in terms of it being at 113,500 BOE's per day. 1,500 barrels that we had lost because of unscheduled down time 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 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, all 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 and gas price. You look at NGL prices, our realizations were down 18% from the first quarter. It 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 U.S., which is 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 Mainland or 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 work-over 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 and is relatively flat with the second quarter when you adjust for the downtime 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're going to see the infrastructure come in the Eagle Ford, the additional production from Tunisia, continued ramp-up of Spraberry and that will be where you will 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 will open up the call for questions.

Question-and-Answer Session

Operator

Thank you. The question-and-answer session will be conducted electronically. (Operator Instructions) And we will take our first question from Dave Kistler with Simmons & Comp.

Dave Kistler - Simmons & Company

Just hopping on to the production guidance for a second at about 113,500 barrels or oil per day. 1.5,000 down as a result of varied down time. And then looking at two incremental 1000 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, et cetera

Scott Sheffield

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, we obviously over time with more history from the Strawn and lower Wolfcamp zones. We hope to update increase guidance obviously with the Spraberry program.

Eagle Ford program is pretty much what it is, we have it really 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 the guidance. So but right now, we see it primarily. As I mentioned, you know, realized only six, seven months ago we were at five rigs in the company. Today we are 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 that we are going to do it.

Dave Kistler - Simmons & Company

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

Scott Sheffield

Obviously.

Dave Kistler - Simmons & Company

I realize the second quarter is a challenge, not challenged, but isn't going to have the full impact of these things yet.

Scott Sheffield

That's right. As I mentioned on that one slide, it only took 20 rigs a 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.

Dave Kistler - Simmons & Company

And then switching over to thank you, 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 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?

Scott Sheffield

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 about 4,000-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're looking for a material bump in the EUR in production that offsets what's a pretty significant increase in the cost of the wells. And I guess the proof is in the pudding. We'll get back to you when we find out the results.

Operator

Next with Goldman Sachs we'll hear from Brian Singer. Brian is using a speaker phone. Pick up your handset and press your mute function. Hearing no response, we'll move to Michael Hall with Wells Fargo.

Michael Hall - Wells Fargo

Good. Congrats on a solid quarter. Just 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?

Scott Sheffield

Yes, of course, the way to think about frac fleets in South Texas is each can frac about 40 wells a year.

Michael Hall - Wells Fargo

Okay.

Scott Sheffield

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, easily the case is that we will be fracing 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's 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.

Michael Hall - Wells Fargo

Okay. Great. And then if I may still I like that slide 16 is 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 condensate prices can pull it off from their relationship to WTI or do you think that's pretty robust pricing market?

Scott Sheffield

Mike, 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, that pushing 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 Canadian crude and other sour crude to help improve the price and so there is still fairly high demand for, five years from now if this country adds a 0.5 million to 1 million barrels of condensate from all these plays and you may have a different issues but right now I don't see any problems.

Michael Hall - Wells Fargo

And then 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?

Scott Sheffield

Yes, I think the most important thing is that based on what we have seen from a couple of the competitors I think you know who they are?

Michael Hall - Wells Fargo

Yes.

Scott Sheffield

We have studied it, being south of them over the last two or three years we decided with all prices trading at 18:1, it's something we all look at and we were surprised about how cheap the acreage is.

It's running about 1/10th the cost as what Eagle Ford acreage is. So you can get the same returns, less competitive. Instead of having 30 people competing with you in 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 mentioned built up to 43,000 acres. We can't give out our targeted range, but we are continuing to buy. And we will have several hundred locations and it will be as good returns at Spraberry as Eagle Ford. So it is nice to have a third play that we can ramp-up significant production over time.

Michael Hall - Wells Fargo

Okay. 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.

Scott Sheffield

I will give you acreage. You know what Eagle Ford. I gave you rounding area. You know what Eagle Ford is going for top of the end, I said 10. Multiply that by maybe a little less than that for 43,000 acres so.

Operator

And next question is from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Going back to Spraberry and Wolfcamp. Can you talk about the timing of the production trajectory as we go into next year? Is it fair to characterize that kind of 20-rig program is giving you a little bit of closer to about 1,000 barrels a day growth per quarter and that based on your guidance 30-rig or 25, 30-rig program will get you more of 1,500 barrels a day to 2,000 barrels a day per quarter. And maybe just comment on expected improvement in productivity per rig as you drill deeper?

Scott Sheffield

Yes, I think the way to couch 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're 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. So what that means is, it's potential that we would have some 20 to 30% upside just in relation to looking at that graph. Now, we'll have to see but at there point in time I'd have to say we are being very conservative.

Brian Singer - Goldman Sachs

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?

Scott Sheffield

Brian, we are just finishing an important well now that's a dual lateral and new exit. It will be coming on and testing over the next several weeks. We are probably most likely our successful marine test that we announced about six months ago it's been flat right now at 600 barrels a day with no decline. So obviously we're going to do some more drilling this coming winter with that. So obviously 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 marine drilling that we're going to do this coming winter and do some more testing and also with water injection well in that regard too. So right now, 2,000 barrels per day per year gross production in Alaska. So say we are at 12 now, roughly. 11 to 12. So adding a couple thousand barrels a day per year.

Brian Singer - Goldman Sachs

Great. Thanks. And lastly, given the growth coming out of Spraberry, Eagle Ford, et cetera, 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?

Scott Sheffield

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

Brian Singer - Goldman Sachs

Africa overall?

Scott Sheffield

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 U.S. and we get a great price for our condensate.

So it will produce out to 2013 and possible extending the reserves could last another five years past that, maybe eight. So we could have possibility of an extension. But right now, we are just going to produce that project out.

In North Africa and Tunisia it is a question of in regard to the three well program. We were drilling these three wells. And t\hen at some point in time made a 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 [Antigo] opens up a whole another 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.

Operator

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

Leo Mariani - RBC Capital Markets

Quick question on the Barnett combo. Obviously you're picking up acreage. You are going to drill some of your initial wells 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 and around your acreage that convinces you as you've got something there.

Scott Sheffield

It is simple. A combination of 3D offset acreage right next to the two main players in the area. Both Devon and EOG, and has 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 on results we have seen from offset operators has got us the confidence level and history from both of those two operators.

Leo Mariani - RBC Capital Markets

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?

Scott Sheffield

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 what we call the BEK block to the south by OMV. OMV is continued. 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 (inaudible) and also BEK, and the recent results we drilled with ENI.

Leo Mariani - RBC Capital Markets

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

Scott Sheffield

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

Leo Mariani - RBC Capital Markets

Okay. I guess in terms of your program here obviously, you've taken up a lot of your own service equipment looks like. You know in the course of the next 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, rigs and frac crews and frac tanks and everything?

Tim Dove

Yeah, Leo, it's Tim. Just to give you just a frame of reference. The Permian basin units, as 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 2X horsepower. Those rigs frankly is going to earn between 35 and 40 million. So, overall, you're probably in the $100 million range in terms of overall cash going out the door for vertical integration.

Leo Mariani - RBC Capital Markets

Okay. And that includes the rigs as well, Tim?

Tim Dove

Yes, that includes the rigs. Some of the rigs of course were purchased last year.

Leo Mariani - RBC Capital Markets

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

Tim Dove

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

Leo Mariani - RBC Capital Markets

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

Tim Dove

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

Leo Mariani - RBC Capital Markets

Okay. So roughly what percentage you are drilling it's going to be in the liquid rich zone next year as opposed to more dry gas roughly?

Scott Sheffield

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

Operator

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

Brian Corales - Howard Weil

Hey, guys, just a couple of follow-ones on the service side are you all planning to add additional services to the Eagle Ford acreage or to for the Eagle Ford?

Scott Sheffield

Well, of course at this point in time the one thing we have added is the frac fleet I mentioned was actually just curve tubing associated with it. They will come in and be in service second quarter of 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 our frac fleet down there has essentially a one-year payout 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. Quite an extensive geographical area. This play covers as oppose to Permian we're all pretty 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 and our Raton operation is working very well at Permian. So I don't see why it wouldn't apply in Eagle Ford in an accelerated fashion as well.

Brian Corales - Howard Weil

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

Scott Sheffield

Well, 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 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.

Brian Corales - Howard Weil

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 kind of evaluated? And also maybe just your general thoughts on the NGL market, and what you are doing to maximize price there?

Scott Sheffield

Yeah, Brian, there is a primary zone called tenant ] shale zone that some of our competitors are looking at seriously. We have taken course recently and looked at it and looking at testing it also. So it is very, very early in the stage. Obviously, it is an important area, 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 setup in Tunisia which is one of the issues.

Brian Corales - Howard Weil

Okay.

Scott Sheffield

We are taking to the next step. But right now, it is all in the study phase. Then regarding your NGL question, I think our goal is to make sure whether it is Spraberry, Eagle Ford or Mid Continent with all the demand of NGLs. Our NGLs with all demand 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 regard to this industry but two to five years you may have a significant problem in regards the question whether or not the petro, petchem ministry 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. So those are the two key ingredients. I don't think anybody really knows. The market, the ethane market and propane market's in contango right now, so it's decent prices. But usually if you look at it in the winter months, we see spikes, so it's hard to sit there and lock in a price today based on potential upsides that we have seen in this past winter. And generally you look at past winters, you do get a bump in ethane and also a bump in propane plus. So our goal is protect ourselves to make sure we can get our product fractionate as I mentioned and also sold.

Brian Corales - Howard Weil

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?

Scott Sheffield

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.

Brian Corales - Howard Weil

Okay.

Scott Sheffield

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 at both ways.

Operator

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

Michael Hall - Wells Fargo

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. Is there any concern that I mean containment kind of frothy and frac prices there Is this a wrong time to be locking in long-time contracts? Or how did you protect yourself in the negotiations there regarding that?

Tim Dove

Well, we have terms we think that are reflective of the current market. With 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. So I will tell you I think we can complete these wells cheaper from our own frac fleet probably to the tune of a $1million cheaper. By virtue of using our own equipment.

Michael Hall - Wells Fargo

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

Tim Dove

Essentially, at current market levels. That's right.

Michael Hall - Wells Fargo

Okay. 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?

Tim Dove

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 what I mentioned to be an outlook that we are looking at which is to say, potentially you got a significant number of wells in the overall play which remains uncompleted. You look at the number of rigs running. And so I think just probably upside potentially in some of the costs there as opposed to downside today.

Operator

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

David Heikkinen - 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 at the current level or as you look forward over the next year? What should web watching for, listening for?

Scott Sheffield

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 going to 40 rigs. We are in the process of contracting the 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, the dedicated team strictly as 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. Then regard to the (inaudible). Obviously, on the service side what's nice when you start out the service frac crews, we see no issues of hiring people because 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'd rather work for an oil and gas company versus a service company. So obviously there's a lot of pluses being an EMP company and being the biggest operator in the Permian basin, so we see no issue there. And same thing is we'll eventually be one of the biggest operators in South Texas with our Eagle Ford fleet. So those are the two areas where the pressure is. We've got the staff, the people and really see no issues. Tim, you got any?

Tim Dove

The only thing I'll 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 in 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.

David Heikkinen - Tudor, Pickering, Holt

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?

Tim Dove

They will eventually succumb people into our office here in Las Colinas and we anticipate that number will be approximately 10. Today they do not have anyone here.

David Heikkinen - Tudor, Pickering, Holt

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's kind of on the horizon that you'd be willing to talk about?

Tim Dove

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.

David Heikkinen - Tudor, Pickering, Holt

How does the 400 locations in the Barnett combo really fill into that strategy?

Tim Dove

What's amazing is that the asset gets up to somewhere between 35 and 50,000 barrels a day over time. By running one to four, 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.

David Heikkinen - Tudor, Pickering, Holt

Okay.

Tim Dove

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

Operator

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

Scott Sheffield

Bob, you got any questions?

Operator

Robert if you're on a speaker phone please pick up your handset and you press your mute function. Your line is open. Hey, no response. Move to Richard Tullis with Capital One.

Richard Tullis - 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?

Rich Dealy

I think it is about $100,000.

Richard Tullis - Capital One Investments

Okay. And that's just one stage frac?

Rich Dealy

Yes, that's right.

Richard Tullis - Capital One Investments

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

Rich Dealy

Well, I think it counts in the Permian Basis we have 20,000 locations if you start getting into 20-acre, locations. So you have to look at more, what's the aerial extent of the Strawn in terms of potential and today we say its 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.

Richard Tullis - Capital One Investments

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?

Rich Dealy

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

Richard Tullis - Capital One Investments

Okay. And 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?

Tim Dove

No, not alt this time.

Richard Tullis - Capital One Investments

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

Scott Sheffield

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.

Operator

And our final question comes from (inaudible).

Unidentified Analyst

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 deep, than if you go from the base of the dean. I'm just looking at your picture on page 10, all the way to the Strawn. And I was surprised that it would only cost an extra $100,000 to go all the way from the base of the dean to the Strawn.

Tim Dove

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

Unidentified Analyst

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

Tim Dove

Yes, I think we've talked about that earlier in our commentary. But 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 the Strawn, we see those well costs increasing just by virtue of the deepening of the wells and they're averaging now 1.1 to $1.2 million.

Unidentified Analyst

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

Tim Dove

I don't think there were any limitations other than to stay we put an outstanding team of geoscientists and engineers on the project of 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, you can expect that our results will improve.

Unidentified Analyst

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 determinant in that 30 to 40%?

Tim Dove

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

Unidentified Analyst

All right. And finally just for deferred taxes I see you gave some idea for the third quarter. What about the fourth quarter? Should we consider that the percentages would remain the same, those two would be the same, third and fourth quarter?

Tim Dove

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

Operator

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.

Scott Sheffield

Again, thanks. We appreciate everybody listening in. Look forward to the next quarter. Obviously, we will continue to add the rig count, increase 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.

Operator

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

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