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Pioneer Natural Resource (NYSE:PXD)

Q1 2010 Earnings Call

May 05, 2010 10:00 am ET

Executives

Timothy Dove - President and Chief Operating Officer

Frank Hopkins - Vice President of Investor Relations

Richard Dealy - Chief Financial Officer and Executive Vice President

Scott Sheffield - Chairman and Chief Executive Officer

Analysts

Michael Hall

Amir Arif - Stifel, Nicolaus & Co., Inc.

Gil Yang - BofA Merrill Lynch

Brian Corales - Coker & Palmer

Leo Mariani - RBC Capital Markets Corporation

Scott Wilmoth - Simmons

Michael Jacobs - Private Investor

Sven Del Pozzo - C. K. Cooper & Company, Inc.

Operator

Welcome to Pioneer Natural Resources First Quarter Conference Call. [Operator Instructions] Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Vice President of Investor Relations.

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

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

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

Frank Hopkins

Good day, everyone, and thank you for joining us. I'll briefly run through the agenda for today's call. Scott's going to be up first. He'll review the financial and operating highlights for the first quarter of 2010. He'll then comment on the company's plans for the remainder of this year and talk a little bit about 2011 and beyond. After Scott's finished with his remarks, Tim's going to provide an update on our recent drilling results and plans for this Spraberry/Eagle Ford Shale and Alaska. Rich will then cover the first quarter financials in more detail and provide earnings guidance for the second quarter. After that, we'll open up the call for your questions. With that, I'll turn the call over to Scott.

Scott Sheffield

Thanks, Frank. Good morning. We appreciate everyone taking the time to listen to us for this quarter. I'll start on Slide #3, our highlights.

First quarter 2010 adjusted income of $58 million or $0.48 per share above consensus, excludes income from unusual items totaling about $23 million or $0.20 per share. And also a non-cash mark-to-market hedging gain of $164 million after tax or about $1.40 per share.

First quarter production, mid-point of guidance, around 114.3. And first quarter was about 7% above fourth quarter, primarily due to excellent drilling results in the Spraberry and Eagle Ford and Alaska. Obviously, resumption of our operations at our GTL plant that was shut in the fourth quarter and then the expiration of a gas VPP.

Obviously, the Spraberry drilling ramp-up is ahead of schedule, current running 19 rigs and on track to be close to 30 rigs by the end of this year. Another successful well with an IP of about 15.6 million equivalent, still with industry-leading results in the Eagle Ford play, 45% liquids. And our JV process is on track as Tim will talk more about later about the Eagle Ford and its results.

We also drilled three key wells, highly productive at both the Kuparuk and the Moraine at Oooguruk project, which will help production significantly going forward. In addition, we started up our rig to drill three operated wells in Tunisia.

We added significant derivative positions, both oil and gas at very attractive prices. Obviously, we did it before the markets adjusted over the last 3, 4 days. In addition, we reduced debt by $113 million, a combination of free cash flow and partial MMS refund, received about $95 million of our expected $150 million so far from the MMS. In addition, our debt to book down to 40%. So we're very, very close to achieving our target of between 35% and 40%.

Slide #4, return to quarterly production growth in first quarter 2010. Obviously by this first quarter, we're already up 7% on our 10% plus target. Obviously, that excludes the Eagle Ford ramp up. Well obviously, we benefit from 5,000 barrels a day of VPP that expired into 2009. We're still one of the few companies with no significant gas drilling, or really no gas drilling on dry gas drilling going on, on our key properties.

CapEx, approximately $900 million. Obviously, we're continuing to forecast strong double-digit annual production growth from 2011 through 2015. And we think it's important to re-emphasize the fact that we are spending within cash flow.

Slide #5, our CapEx. Obviously, based on the current matrix chart, we're currently -- based on the current strip as of yesterday, now it's obviously, it's off today. But we're about $1.1 billion cash flow based on that and where our store is. CapEx, about $900 million. That includes 440 Spraberry wells and a 2-rig Eagle Ford program. Obviously, we'll be ramping that up somewhere within six and seven rigs by the end of the year. And again, obviously, as I've mentioned, it does not include ramping up Eagle Ford over the next two or three quarters.

Turning to Slide # 6, on 2011. With our three ways and our current hedging at roughly about 85% are both gas and oil. We expect about a little over $1.4 billion of cash flow. Our CapEx obviously will be going up this year, primarily drilling another 300 Spraberry wells. So roughly, we'll be going up about $300 million. So still, a way underspending cash flow.

Slide #7. Obviously, the two key growth engines inside Pioneer today is the Spraberry Trend Area fields and the Eagle Ford Shale. It makes up 80% of our total resource potential, both prove and total resource potential. Obviously, you have two key areas that will be getting up to about 55 to 56 rigs over the next two or three years. Obviously, significant upside to move into the proved category over the next several years.

Finally, on Slide #8, Why Invest in PXD? obviously, we're one of the most liquid-rich companies. We don't have to say that we're shifting to liquids-rich areas. We've already been doing it, greater than 75% liquids. Obviously, we're ahead of schedule on our Spraberry Trend Area field. And on schedule and be ramping up shortly, significantly into the Eagle Ford Shale play with industry-leading results.

Forecasting double-digit annual production growth. Obviously, we'll be updating that number after our JV process is concluded by end of June, and discuss after that our growth rates in Eagle Ford and how it affects the company. Continue to deliver free cash flow as we did in '09 and '10 through 2015. Right now, we're running 45% liquids. It represents about 70% of our cash flow. That 45% would be going to 60% and the 60% will be going to over 80% within five years, in regard to our cash flow.

Generating strong margins. And again, attractive derivative positions, we'll continue to hedge as long as the market's in contango using three ways and try to stay about 2 to 3 years ahead of schedule. It's important to maintain in this market, obviously, strong financial flexibility.

Let me turn it over to Tim to go over our assets.

Timothy Dove

Thanks, Scott. As the title of Slide 9 says, we are ahead of schedule in terms of ramping up our Spraberry drilling campaign. Our production in the first quarter was right on target, at about 31,000 BOE per day. That's up about 2% compared to the fourth quarter of 2009, as we begin to show what we might expect from incrementally adding to the drilling campaign and ramping up production. As a result, we drilled about 81 wells during the first quarter, heading towards a total campaign of 440 wells this year. Our original forecast was for about 425 wells.

As I said, we're ahead of schedule. And in fact, we have 19 rigs running today. That number was originally targeted for midyear. So we are ahead of schedule and plan to still get to the 25 to 30 rigs by year end that will allow us to then drill some 700 wells in 2011. That's about, what a 30-rig average would accomplish for next year.

Importantly, all of the wells we're going to be drilling this year in the Spraberry Trend area, we'll be adding incremental production reserves from -- deepening the wells into the Wolfcamp, as well as completing the wells in the shaly/silty intervals that we have proven have additional pay to contribute to well bores.

And importantly as well, as we look forward, we're not stopping there when it comes to technology applications. We are planning to test the deeper Strawn, which sits directly below the Wolfcamp in several wells as we get to the second half of this year. And we'll be drilling some horizontal wells in the Wolfcamp in the second half of this year. In fact, we have one location already picked for about a 4,000-foot horizontal in the lower Wolfcamp. So we'll be reporting more on those results as we get into the periods later this year.

Our returns are still exceptionally strong. And we expect them to continue in that way. This asset is the underpinning of the growth of the company. It's going to be growing a minimum of about 10% from fourth quarter last year to fourth quarter this year.

The Waterflood's going extremely well. We've got about 50% of the facilities put in place. We expect to start injecting water in the third quarter. And as we've been talking about through time, expect an oil response in the neighborhood of 6 to 9 months thereafter. So we're looking at early 2011 as to having impact to the production from that area. And then the idea would be to develop Waterflood plans throughout the field area.

Turning to Slide 10. The Spraberry development plan I've commented on earlier is really a critical aspect of any foundation for the overall company's growth rate when it comes to production, reminding you that this is really manufacturing oil. We have 10 of our own company oil drilling rigs that was not purchased. We have a frac plate we brought down from Raton. We've bought two additional frac plates that will be in place by the end of the year. All of our tubulars and pumping units are in place through 2011. And our sand supply, when it comes to those fracs, is in place through 2012. The idea is to control our margins and to whatever extent we can, control our cost, looking forward by vertically integrating in this field in the same way that it was successful in our Raton area of operations.

And looking forward, as we increase the campaign to 700 wells next year and a 1,000 wells thereafter, we can point to about a 25% CAGR, in terms of production growth from these activities. So I guess where we are today is, we're getting a lot of confidence that this early execution we're seeing allows us to be well on the way to meet these long-term goals. And this is something we're very good at. And I think we can achieve in a very good way.

Now turning to Eagle Ford Shale, Slide 11. Separately today, we announced our fifth successful well at Eagle Ford Shale, that's the Chestnutt #1. It's shown here on the a map as being central to our acreage, actually between several other wells we drilled. It made about a 14.1 million cubic feet a day in IP and about 255 barrels a day. [indiscernible] and say on a 4,100-foot lateral, it does have the 1,200 BTU gas. It's liquid-rich gas, which is important to the economics of these types of wells in the condensate window. And we pumped a 12-stage frac on this well.

So very pleased to see another leading IP rate of the five wells we've drilled. So for, these are some of the best wells that have been drilled in this trend. We have a couple of wells that are currently drilling with our 2-rig campaign, both in Dewitt and Karnes Counties. And we have a well that's awaiting completion in Live Oak County.

Suffice it to say, this gives us a lot of confidence in the high quality of our acreage, and also, really, the aerial extent, what we think is a prolific basin here in the Eagle Ford Shale along Pioneer's acreage position.

And then going to Slide 12. This asset has significant resource potential. It's a very large prize. And one of the objectives of our joint venture is to accelerate development of that price. Our data room, that was closed a couple of weeks ago. We expect bids to be due shortly. We'll be evaluating those bids. And the objective is to announce a joint venture by the end of the second quarter.

In association with a joint venture, our plan would be to aggressively begin increasing the rig count, planning to have -- in fact, we have contracted and will have contracted six to seven rigs by the end of this year, going to 10 rigs in 2011 and 14 rigs in 2012. And by virtue of that campaign, we can do two things. One is we can preserve our lease hold. Secondly, we can accelerate the significant amount of production in proved reserves that are associated with this play. We have some 1,750 locations on the map, ready to drill. We expect still in the neighborhood of 6 BCFE per location. We are, fortunately, in a position where about 70% of those locations are within the liquid-rich window. So Eagle Ford Shale's doing exceptionally well we're certainly looking forward to the results of these discussions surrounding the JV.

I'm going to turn now to Alaska on Slide 13. It's our third major area of oil activity, oil drilling activity. We drilled two very successful Kuparuk wells. These are the wells we drill typically in the winter. And those average, on a combined basis, about 7,500 barrels a day of IP basis gross. One of those will have to be converted it to an injector over the next few months. The need here is to make sure we're injecting as much water into the system as we're taking out in the form of oil. And so that will be needed in the next few months.

Separately, we tested -- as Scott had mentioned, another reservoir called the Moraine. I'll touch more on that on the next slide and give you a little more detail as to what that really means to the project. During the summer and continuing to the end of the year, we'll finish a Nuiqsut campaign, which will include two producers and two injectors. And also during that campaign, one of those wells, producing wells will be drilled as a dual lateral. It's our first dual lateral to test the ways to optimize recoveries as well as reduce costs. First quarter production was about 6,000 barrels a day. We see growth for the year of about 60% to 70%, compared to last year's total year production, as we continue the drilling campaign.

Slide 14 on Moraine. This is something we haven't talked too much about in the past. But I'll give you a little bit of detail on what this means to our Alaska operations. First of all, as you see on the right, those are logs are producing horizons [ph]. Moraine is a large geographic [ph] trap of thinly-laminated sands that sit some thousand feet above, let's say, the Kuparuk Reservoir. They're about 200-feet thick. We expect there to be, in the neighborhood of 50 to 100 million BOE, barrels of oil recoverable from this Moraine horizon.

And actually several wells have been drilled in the Moraine. Of course, every well we've drilled into the Kuparuk and the Nuiqsut have been drilled through the Moraine. So we have a lot of data. Although as you can see on the map, our drilling in relation to the island has typically been in or near the water leg associated with the Moraine. 12 expiration wells have been drilled here by others. The significant ones are those being in the mid-80s when Texaco was testing oil from vertical frac wells in the Moraine.

And our recent well is important, looking forward to a potential development in the Moraine. It was a 3,000-foot lateral as shown here on the map extending from the island into the Northern Reaches of the Moraine prospect area. And it was a frac-lateral well that produced an IP basis about 1,100 barrels a day. And the early production we see from this well gives us a lot of confidence that we have good reservoir productivity, which was one of the main objectives for drilling the well. And as we look forward, one of our objectives will be to do some long-term testing, and perhaps even a Waterflood Pilot to test the level [ph] of continuity of the reservoir itself.

If you look forward as to possible developments, we will be looking at potentially drilling two or three more wells from the island into Moraine, perhaps early next year. And eventually, a Waterflood Pilot. And then the real key to this is the potential to move onshore and drill the Southern Reaches of this prospect from an onshore gravel pad drill site. This would involve extended reach drilling from that pad.

And so this is a very interesting development to continue to enhance the value of the Oooguruk, as well as the confirmation of its resource potential. It gives us a lot of confidence that we're now confirming the idea that the island and its extension in the Moraine and the existing reservoirs have potential that's in the neighborhood of 120 million to 150 million barrels of oil.

Scott also mentioned we have commenced drilling in Tunisia, a three-well campaign. We also have a three well in non-op campaign that's being undergoing right now with ENI as the operator.

I'm going to stop there and pass it to Rich for a discussion of the first quarter financials and second quarter outlook.

Richard Dealy

Thanks, Tim, and good morning. Turning to Slide 15. Net income attributable to common stockholders was $245 million or $2.08 per diluted share for the quarter. As Scott mentioned, that did include $164 million or $1.40 per share of derivative gains that were non-cash, really reflecting forward commodity prices declining from December 31 to March 31, and as you guys are aware, principally related to gas prices.

In addition, income did include another $23 million of income related to these three items listed on the page or $0.20 per share. We were able to sell part of our Uinta/Piceance assets during the quarter. We did receive some Alaska Petroleum Production Tax credits in cash for the quarter. So we recognized that. And in addition, we did get some insurance money in related to our East Cam 322 [East Cameron 322] platform project that happened back in 2005, and we still expect in the future of substantial insurance reimbursements as we move forward as well. So netting all that together, $58 million of adjusted earnings or $0.48 per diluted share.

Looking at the bottom of the Slide 15, where our results compared to our guidance. You can see as we mentioned that production was at the midpoint of the guidance range. And all the other items were very close to either inside guidance or very close to guidance. And so they're there for your review.

Turning to Slide 16, look at realize prices. You can see from oil prices, they were essentially flat with the fourth quarter, up 1%. NGL prices continued to move up. And they were up 11% compared to the fourth quarter, the $41.82 per barrel. And as you look at gas prices, they were up 16% relative to the fourth quarter, up to $5.30. Clearly that benefited from gas prices being stronger in the beginning of the quarter and have since falling back some. So expect second quarter realization to be somewhat lower.

Also to point out here, you can see that the VPP that we talked about at the fourth quarter call is gone at the end of 2009. And so we have no more gas-associated VPPs. Looking at the bottom of the slide, derivative impact included in price. That bar just shows what's the effective or derivative position that's included in the prices I mentioned above. Those will continue to just climb as we've discontinued hedge accounting. The second line really shows the impact of our derivative position that really will reflect our ongoing impact of our hedging positions.

Turning to Slide 17 on production costs. If you look at the first quarter relative to the first quarter of '09, were down about 7%. As we've talked about in previous calls, really a big effort by our asset teams to cost control over the last 18 months has driven most of that change. In addition, as I mentioned, the expiration of the VPP helped on a per unit basis as we brought those production volumes back into our denominator. Similarly for the first quarter, relative to the fourth quarter, same level of improvement. But we also resumed production in our South Africa gas project, when PetroSA brought back on their GTL plan, and had a low cost of average on a production-cost basis since that helped lower our per BOE cost as well.

Turning to Slide 18, we put this in just to show how our cash cost compared to our peer group. This is a study that was done by Crédit Suisse for 2009. You can see that for 2009, we are at $17.10 on a cash cost for interest G&A and production costs, relative to our gas-focused peers and our oil-focused peers. You can see how we performed. The think what [ph] Important is we're one of the oilier companies in the peer group, as you guys are aware. And so we compare quite favorably to those oil-weighted companies. Overall, you can see, we're down about 16% on a total cash cost basis, down 25% on a production cost basis. I think this highlights the fact that our cost structures is very competitive with both the gas-focused and oil-focused peer group.

Switching to second quarter guidance on Page 19. If you look there the production guidance is 113,000 to 118,000 BOEs per day, really affecting our production growth that we are seeing from our ramp up in drilling activity. If you look at the other items on this page, they're very similar, if not the exact same as our first quarter guidance. And so I won't go through those in detail. But they're there for your review. So take a look at those. Also, when you look at Slide 20, we really have a number of slides in the back for supplemental information. I encourage you to take a look at those when you get a chance. Why don't we stop there and we'll open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions]And we'll hear from Scott Wilmoth with Simmons & Company.

Scott Wilmoth - Simmons

Looking at these Spraberry with additional of the lower shale and silt zones, is the 15% to 20% improvement still what you guys are seeing on those wells? And how is that translated into improving EURs?

Timothy Dove

Scott, this is Tim. I think we can say defensively, based on the work we did and year before last that, that 15% to 20% number is pretty good, especially in the consideration of just the shaly/silty zones.

What we don't yet have -- and the main part of our acreage is deepest Wolfcamp contribution. Although we have seen some very encouraging signs that it may add a significant percentage of additional EUR as well. You just got to give us a little more time to get this drilling campaign finished this year, we'll be able to put a lot more about that through time.

Scott Wilmoth - Simmons

And then obviously, with improved well performance and the acceleration of Spraberry will halt [ph] schedule. How do you guys feel about your 10% quarter-on-quarter versus fourth quarter guidance, is that bias higher at this point?

Timothy Dove

I would simply say that we try to be conservative on this guidance, and we're trying to over perform.

Scott Wilmoth - Simmons

And then in the Eagle Ford, obviously, very good well results to date. Any early indications of what EURs look like out of the liquids-rich versus the dry gas window?

Scott Sheffield

We still need more time, but the dry gas windows are going to be a little bit higher than the liquids-rich, so maybe 10% to 20% higher on dry gas.

Scott Wilmoth - Simmons

Seems like most of the Eagle Ford acreage at this point has been fairly proved up, either by your activity or other operator activity. Any plans to test the northeastern DeWitt County acreage passed the Riedesel #1 well and when could we expect that? And what are your expectations out of that area?

Scott Sheffield

The acreage in our data room is cut off at the DeWitt-Lavaca County line. And we will eventually get up in that area and drill. But we're obviously, with the success of the Riedesel, the pay zones are about the same thickness all the way up to the county lines. We'll eventually be getting up there but we're very confident in that part of the acreage.

Scott Wilmoth - Simmons

And then with the -- obviously, we'll know more once the JV is announced. But in terms of the drilling rig ramp expected in the Eagle Ford in the second half of the year. Do you guys have a range of CapEx earmarked? Obviously, it will depend on the specific JV agreement of how much you guys are targeting to spend in the back half of the year at Eagle Ford?

Scott Sheffield

It's a question of when we get the 6 to 7 rigs running. So we don't know if they're going to be running late third quarter or by the end of fourth quarter. So we will lay that out in the July call.

Operator

And next we'll hear from Amir Arif with Stifel.

Amir Arif - Stifel, Nicolaus & Co., Inc.

One on the capital costs. Just as you guys are adding more rigs and the rest of the industries is adding more rigs in the area too. Are you seeing any cost pressures on the million per wells that you are assuming?

Scott Sheffield

Most of our rig costs have been locked in for all of 2010. So we're seeing very little pressure because of our cost are locked in through 2010. That's on the third-party rigs that we contracted. We do not know about 2011 yet.

Amir Arif - Stifel, Nicolaus & Co., Inc.

In terms of the Wolfcamp, can you talk a bit more about the horizontal potential that you're looking to tests? Is this simply a way to lower the cost per barrel, or are you looking at other potentials in terms of better ways to recover the reserves?

Timothy Dove

I think what you're looking at here is, we have very high quality rock in the Wolfcamp, either in the middle part of the Wolfcamp or the deeper part of the Wolfcamp. And testing out basically new horizontal and frac technology to see whether we can incrementally add significant reserves and production rates from that high-quality rocks. So we'll have to get back to you with the results, but that's the objective.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And those wells -- the first couple of horizontals are scheduled for the third quarter?

Timothy Dove

Yes.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And then just shifting over to the Eagle Ford, how many acres of -- I think you guys owned about 320 gross acres out there. How many acres are going to be inside the JV?

Scott Sheffield

It will be -- roughly 310,000 gross.

Amir Arif - Stifel, Nicolaus & Co., Inc.

Are you adding any acreage currently inside or outside of the JV area?

Scott Sheffield

Both.

Amir Arif - Stifel, Nicolaus & Co., Inc.

Both?

Scott Sheffield

Yes.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And then just a final question in Tunisia. Can you just give us a sense of the prospect side for the three non-op wells that you can be drilling out there? What you're thinking about to begin with?

Scott Sheffield

We'll be drilling about 2.5 million to 5 million barrels per prospect.

Operator

And the next question will come from Michael Hall with Wells Fargo.

Michael Hall

Can you talk just a little as you've been getting some experience in the Eagle Ford here. We've seen some variability obviously within your wells even in nearby -- in the neighboring wells, in terms of kind of barrels per million, or kind of yield, if you will. I'm just trying to think, what do you think is the kind of the key driver in ferreting out, what that will look like across the play?

Scott Sheffield

It's based on -- we've drilled 150 wells through the Eagle Ford and taking course in our 3-D data. So that's why in our acreage, we pretty much know the -- geologists have been right on. Everywhere we've drilled they have actually predicted the condensate yield before we spud the well. They have been right on. So it's all the data that we picked up over the time and the years.

Michael Hall

Any key variables that they're keying off of that might help us and think about the play as a whole?

Timothy Dove

I think the real answer to that is we were able to predict, as an example, with the Crawley #1 # well will be dry gas, even though it's only a couple of miles away from the Sinor #5 by virtue of the data that Scott said. So one of the keys is going to be depth and there's temperature, and we've got that pretty much lined up from a data standpoint.

Michael Hall

And then thinking about infrastructure needs on your acreage within the JV. Can you talk about what the plans are there and what sort of condensate stabilization capacity you have, what you think you need, what the gathering environment looks like on your acreage?

Scott Sheffield

Yes, we have a slide. In fact, I guess, I think it's in the appendix. It's in our typical investor presentation but there's plenty of capacity in the area, both for liquids, NGLs and also dry gas.

Michael Hall

I guess I'm thinking more on a gathering level within your own acreage on your fields, getting to that capacity that's outlined on that slide.

Scott Sheffield

Yes, our goal is to build to the existing entities, midstream entities to them. So we're going to build central and gathering facilities. That's why some of our wells, which will may -- potential may take two or three or four months before we connect. Because we want to build our own system and be able to profit into the downstream and midstream markets.

Michael Hall

And any discussion on CapEx required there?

Scott Sheffield

We'll be laying that out when we have announced the joint venture in July.

Michael Hall

Completion crew availability, I've been hearing of some tightness particularly the -- in the western extent of the play. How's that looking at this point, what's the outlook look like from your perspective?

Timothy Dove

I think it is tight, there's 45 or 50 rigs running. But what we're seeing is really just leads to slight delay. We might have to wait a couple of weeks to frac a well, as opposed to having it done the next day, that kind of thing. So I don't think it's terribly significant in the overall timeline of the player who is going to be drilling wells for multi- years, but we are looking at a couple of week delays for fracs.

Operator

And next in queue we have Michael Jacobs with Tudor Pickering Holt.

Michael Jacobs - Private Investor

I wanted to follow-up with some Spraberry questions. I didn't see a type well in the presentation, are you still assuming the 110,000 BOE recovery per well?

Scott Sheffield

Yes. We're going to wait another several months to build based on the silty shale from the Spraberry and also the deep Wolfcamp, since we're opening up all those zones now and all of our wells, we need about six more months at least before we come out with a new tight curve.

Michael Jacobs - Private Investor

And I understand your desire to remain conservative on tight curve guidance and I'm certainly not trying to pigeonhole you. But can you give us some analogs on the wells that you have deepened as it relates to early time production, and how that compares to early time production in the 110,000 BOE case?

Scott Sheffield

Yes, I think the difference has been -- we've had several wells that are producing 70 to 90 barrels a day. The initial rate versus a tight curve well coming in about 50 barrels a day.

Michael Jacobs - Private Investor

And then looking at your Slide 10, you show 700 wells next year. But just kind of doing the simple math of two wells per rig, per month. If you started -- if you go into 2011 at 25 to 30 rigs, and you end the year at 40 rigs. I kind of get over 800 wells, and I'm just wondering why you didn't update that 700 well guidance for 2011?

Scott Sheffield

We are assuming that we're running 30 rigs flat in that right now, at this point in time. And what happens is that you don't start 10 rigs on December 31, 2011. So at some point in time, we would increase the rig count in the fourth quarter, and slowly ramp up to the 40 rigs. But right now, our assumption is just 30 rigs flat all year long.

Michael Jacobs - Private Investor

I saw some language in the press release about non-operated activity in Tunisia. I think before you were talking about three wells in total, now it sounds like you're going to do six wells, with three of those being non-op, any color there that you can provide and I'll hop off?

Scott Sheffield

The D&I [ph] on our southern blocks are drilling several appraisal wells, and so we'll be reporting on those probably next quarter. In addition, we're shooting, there's been some big discoveries by OMV even further south on our southern block, and we have a big 3D shoot that's in the process of completing, offsetting those discoveries.

Operator

And next we'll hear from Leo Mariani with RBC Capital.

Leo Mariani - RBC Capital Markets Corporation

You're talking about some pretty good increases in your IP as a result of adding the silt and shale zones here. Are you still at the $1 million cost when doing that? Would you still be at a $1 million cost, I imagine that we go higher regarding the Wolfcamp? Just trying to give us a sense of some of the costs surrounding adding those zones.

Scott Sheffield

Right now, we're probably going to be, including the Strawn, closer to $1.2 million going into 2011. And so these next 20 wells that we're going to test the Strawn on, the first half of the year, obviously, we averaged $1 million. But going to the deep Wolfcamp and going to the Strawn, obviously well cost will go up. But we expect a substantial increase as we're seeing in production and reserves. It could be as high as $1.2 million, if we include the strawn.

Leo Mariani - RBC Capital Markets Corporation

Obviously, you guys had known of the existence of Strawn at Wolfcamp for quite some time, just curious as to kind of why at this point in time you're deciding to go out and have the Strawn do a lot of wells, and why the timing is right for horizontal wells in the Wolfcamp? Are you seeing other industry players out there with success that you're trying to replicate?

Scott Sheffield

Yes, it's a combination of that. But our success of the last two years in the middle Wolfcamp, in the heart of the fields has been very successful. So since we made a decision to open up the middle Wolfcamp in all zones. Wolfcamp is about 1,500 feet thick. And so since we're going down through the middle already and opening up every well, the next step over the last six to nine months was open up the lower Wolfcamp. So we open up the lower Wolfcamp, tested about 30, 40 wells. Very productive in the lower Wolfcamp, the bottom 200 to 300 feet. So we made a decision to take every well down to lower Wolfcamp just recently. And now we're doing the same since the Strawn is right below the lower Wolfcamp, where it turns out that every time we add another couple of hundred feet of pay, it's easy to go to the next 200 feet. And so Strawn has pretty much -- before we go into some higher pressure Devonian, fosemon [ph] areas, this is about as deep as you can get. We will have to get co-mingling permits and change the build rules, if the Strawn is successful. There's been several strong tests by us and by other operators. And so we're going to see how large of area it is in the Strawn before we make a decision to take a lot of the wells down to the Strawn.

Leo Mariani - RBC Capital Markets Corporation

Obviously, I was thinking you had some additional success here in Alaska. Just curious as to what you guys had booked in proved reserves in year end '09, trying to get a comparison with that in your 130 million to 150 million barrel target.

Timothy Dove

Leo, that was about 16 million, 17 million barrels.

Leo Mariani - RBC Capital Markets Corporation

And you got to think over the next two to three years, you'll be able to hopefully get to your target there?

Timothy Dove

Well, we've got several years of drilling and although it won't be necessarily two years or three years but over the next several years we'll be putting significant reserves.

Operator

Next we have Sven Del Pozzo with C.K. Cooper.

Sven Del Pozzo - C. K. Cooper & Company, Inc.

Do you have enough data yet from your earliest horizontal Eagle Ford wells to give us some idea of what kind of decline rates you've seen after about a month or so?

Scott Sheffield

Yes, it's still running in about a 75% decline rate. So it's matching pretty much to our tight curve. The only well that's not matching our tight curve is our first well. The Sinor because it's only a 3,000-foot lateral. But all of our 4, 500- to 5,000-foot laterals are matching or above our tight curve of six Bcf.

Sven Del Pozzo - C. K. Cooper & Company, Inc.

Could you confirm for me again the 75% decline rate is over what period of time?

Scott Sheffield

That's basically the first month, year, throughout the first year, yes.

Sven Del Pozzo - C. K. Cooper & Company, Inc.

Oh, so 75% over the first year? So the IP rate will be only -- the production rate will only be 25% of what the initial production rate was after one year.

Scott Sheffield

One year. Exactly.

Sven Del Pozzo - C. K. Cooper & Company, Inc.

And I remember your Tunisian drilling program could be meaningful in terms of the production contribution because the wells come on pretty strong. Are we still -- but that was from a couple of years ago that I recall. What about now, is it still the same type of wells?

Scott Sheffield

Yes, we're drilling one exploration well and two appraisal wells. Obviously, our production has been fairly flat, with no drilling over the last 18 months. And so based on 3-D seismic reprocessing, we feel like two of the fields are much bigger. It could be several well development projects. And then we'll drilling an exploration well up in Anaguid.

Sven Del Pozzo - C. K. Cooper & Company, Inc.

What about the Kuparuk wells, those seem like pretty big wells. So I'm wondering, when that other well that's producing is converted to repressurized the reservoir. Should the -- will that 7,500 barrels a day, how long will that be producing at that rate for?

Timothy Dove

Well, I think the answer still as yet undetermined. I think the larger of the two of those producers will be the one that uses an injector, so it will be a matter of several months before we turn it around to injector.

Sven Del Pozzo - C. K. Cooper & Company, Inc.

And did you mention, I might have missed it in your comments, did you say that room is close or it's still open for the Eagle Ford Shale?

Timothy Dove

It's closed.

Operator

And the next question will come from Brian Corales with Howard Weil.

Brian Corales - Coker & Palmer

Believe or not, another question on the Eagle Ford. How much lease hold is still available? And can you maybe comment on prices that you're paying for any blocks that you all are leasing?

Scott Sheffield

It's mostly small blocks, I mean I just saw what Forest just picked up, 100,000 acres, they announced it. I mean it's -- people, it's such a -- it's 250 mile always the border. So people are buying, it's pretty several miles from north to south. So people are still -- Shell just made an announcement, Talisman made an announcement. But there -- most of the opportunities I think are -- there are several small independents that have data rooms open 20,000 to 30,000 acres. In our area, we're paying up to couple of thousand per acre in that area. And they're mostly small areas.

Brian Corales - Coker & Palmer

And just to -- you have a pretty aggressive capital budget going forward. Where and when, if ever, I guess in the near term, do you start going after some of the gasier in place, whether it's the Barnett or the Raton. When do you start putting capital there to try to -- I know Shell declined, but at least helps stem that decline?

Scott Sheffield

We need to see a $5 gas market or better and have confidence in, until even now we're hedged but we need to be confident in the $5 gas market.

Brian Corales - Coker & Palmer

Even in the Barnett?

Scott Sheffield

The Barnett, we're looking at starting a rig up some time in the third or fourth quarter in the liquids rich area.

Operator

We'll hear next from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

The horizontal in the lower Wolfcamp, do you plan on re-entering a vertical well, or will that be a new drill?

Timothy Dove

That will be a new drill.

Gil Yang - BofA Merrill Lynch

Do you think there's an opportunity when you -- if that becomes a program that's viable, would you drill that and co-mingle vertical and horizontal production?

Timothy Dove

Yes.

Gil Yang - BofA Merrill Lynch

Is there a particular reason that you're going to drill in the lower Wolfcamp as opposed to one of the other many formations that you have there? Or is it possible you could also drill into some of the other formation as well?

Timothy Dove

The current plan, Gil, is to drill the first of these wells in the lower Wolfcamp and probably the second one would be in the middle Wolfcamp, is the current thinking but we'll see as we get these wells prognosed. But I think the Wolfcamp has excellent quality rock for this kind of application and that's why we're drilling them there.

Gil Yang - BofA Merrill Lynch

I guess the Wolfcamp is sort of the ideal zone to drill into because it's not been vertically penetrated quite as much as the other zones about it?

Timothy Dove

I think we're just talking rock quality more than anything else.

Gil Yang - BofA Merrill Lynch

When the waterflood gets going and you start injecting water, is that going to lower your LOE for the rest of the operations, or is it not a big enough scale operation yet to have that benefit?

Timothy Dove

Yes, it's not nearly big enough to impact the overall scale of our LOE. It's only 7,000 that's being work plus of acres. So you put that in the context of the 900,000-acre position, you can see -- we can lower operating costs there a lot and not have any impact to the bigger numbers. But the most important thing is that the project itself is a way to lower operating costs, because everyday out in the Permian Basin we produced 4 barrels of water or so for every barrel of oil. So this is a low-cost way to, in essence reinject water that would otherwise have to be disposed. So in actuality, it gives us very good advantage in this kind of a project when we get the cost savings.

Gil Yang - BofA Merrill Lynch

And can you quantify the cost savings on some fashion for of a full-scale, ramp-up basis?

Timothy Dove

I think it's typical to -- some areas of operations that cost $2 to haul water. I think less than that in a lot of areas in the Permian. But essentially, no cost to reinject it in this waterflood because we're not pumping under pressure. It's a very low horsepower project. As it's really more of just introducing water back into the same systems. It is significant cost savings compared to the most expensive ways of disposing of water, which is hauling it away by truck.

Gil Yang - BofA Merrill Lynch

And then the lifting cost for the waterflood production itself, is that different from the lifting cost in isolation, except for the water issues. Are those lifting cost similar to the Spraberry production'

Timothy Dove

Yes, that will be identical.

Gil Yang - BofA Merrill Lynch

In Kuparuk, can you remind us what the typical wells look like in that area? And what was different about these wells that were so productive?

Timothy Dove

These are high productivity wells, very excellent quality sands. We've seen wells with IPs up to 7,000 barrels a day, 7,500 barrels a day in the Kuparuk. So it's not unusual to have this high-quality results at the Kuparuk sands. And that the wells typically produce at relatively high qualities for a longtime. And we've been really impressed by the quality of this production and its longevity. In fact, we've been increasing Kuparuk reserves as a result through time.

Gil Yang - BofA Merrill Lynch

So we should see a potential pick up in the volumes coming out of Kuparuk because of these wells?

Timothy Dove

Well, I think overall, there's a lot of moving parts, right? Because you've got the Kuparuk wells, one of which will have to be reconverted into an injector. Overall production will be up about 60% to 70% on a year-to-year basis, counting all the sources including Moraine.

Operator

And with no further questions, I'd like to turn the call back to our presenters for any additional or closing remarks.

Scott Sheffield

Again, we appreciate everyone participating in the call. If you got any more questions, please call Frank, our Investor Relations department. Again, we'll see you next quarter. Thank you.

Operator

And that does conclude today's teleconference. Thank you all once again for your participation.

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