先鋒自然資源 (PXD) 2010 Q1 法說會逐字稿

Welcome to Pioneer Natural Resources first quarter conference call. Today's call is being recorded. 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," 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. 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.

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 is finished with his remarks, Tim is going to provide an update on our recent drilling results and plans for the 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.

Thanks, Brian. Good morning. We appreciate everyone taking the time to listen to us for this quarter. Start on slide number three, 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, noncash market-to-market hedging gain of $164 million after tax or about $1.40 per share. First quarter production, midpoint 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, a resumption of our operations at our GTL plant that was shut in fourth quarter. And then, the expiration of a gas VPP. Obviously, the Spraberry drilling ramp-up is ahead of schedule. Currently 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 our 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 have adjusted over the last three or four 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 number four, return to quarterly production growth in first quarter 2010. Obviously, by just first quarter, we're already up 7% on our 10% plus target. Obviously, that excludes the Eagle Ford ramp-up. 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 of 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 number five, our CapEx. Obviously, based on the current matrix chart, we're currently based on the current strip as of yesterday. I know -- obviously, it's off today but we were about $1.1 billion cash flow. Based on that and where our star is, CapEx about $900 million. That includes 440 Spraberry wells and a two rig Eagle Ford program. Obviously, we'll be ramping that up somewhere between six and seven rigs by the end of the year. And again, obviously, as I mentioned, it does not include ramping up Eagle Ford over the next two or three quarters.

Turning to slide number six, on 2011, with our three-ways and our current hedging at roughly about 85% of 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 it will be going up about $300 million. So, still way underspending cash flow. Slide number seven. Obviously the two key growth engines inside Pioneer today is the Spraberry Trend Area field and the Eagle Ford Shale. It makes up 80% of our total resource potential, both proved and total resource potential. Obviously, 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 number eight; 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, with greater than 75% liquids. Obviously, we're ahead of schedule in our Spraberry Trend Area field and on schedule and be ramping up shortly and 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 effects the Company.

Continued to deliver free cash flow, as we did in 2009, in 2010, 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. We're generating strong margins. And again, attractive derivative positions. We'll continue to hedge, as long as the markets in Contango are using three-ways and try to stay about two to three 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.

Thanks, guys. As the title of slide nine 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. 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 drill some 700 wells in 2011. That's about what a 30-rig average would accomplish for next year. Importantly, all of the wells where we'll be drilling this year in the Spraberry Trend Area will be adding incremental production reserves from deepening the wells into the Wolfcamp, as well as completing the wells in the shale/silt intervals that we have proven have additional pay to contribute to the 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 Straughn, which sits directly below the Wolfcamp and 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.

Now, returns are still exceptionally strong and we expect them to continue that way. And this asset is the underpinning of the growth of the Company, which is going to be growing at a minimum of about 10% from the fourth quarter last year to fourth quarter of this year. The waterflood is 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 six to nine 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 ten. The Spraberry development plan, I've commented on earlier, is really a critical aspect of and a foundation for the overall Company's growth rate when it comes to production. Reminding you that this is really manufacturing oil. We have, we have ten of our own Company oil drilling rigs that we've now purchased. We have a frac fleet we brought down from Raton. We've bought two additional frac fleets 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 costs, looking forward, by vertically integrating in this field in the same way that it was successful in our Raton area of operations. Now looking forward, as we increase the campaign to 700 wells, next year and 1,000 wells thereafter, we can point to about a 25% [kegger] in terms of production growth from these activities. So, 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.

Okay, now, turning to Eagle Ford Shale, slide 11. Separately, today, we announced our fifth successful well at Eagle Ford Shale. That's the Chestnut #1. It's shown here on the map as being central to our acreage, actually between several other wells we've drilled. It made about 14.1 million cubic feet a day in IP, about 255 barrels a day of condensate, on the 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 far, 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 two-rig campaign, both in DeWitt and Karnes Counties and we have other wells 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 that 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 was to accelerate development of that prize. Our data room 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 the joint venture, our plan would be to aggressively begin increasing the rig count. Planning to have -- in fact, we have contracted or will have contracted six to seven rigs by the end of this year. Going to ten rigs in 2011 and 14 rigs in 2010.

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 and 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, the Eagle Ford Shale is doing exceptionally well. And we're certainly looking forward to the results of these discussions surrounding the JV.

I'm going to turn now to Alaska, slide 13. It's our third major area of oil drilling activity. We drilled two very successful Kuparuk wells. These are the wells we drill, typically, in the winter. And those average, on the combined basis, about 7,500 barrels a day of oil, an an IP basis, gross. One of those will have to be converted to an injector over the next few months. The need here is 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 bit more detail as to what that really means to the project. During the summer and continuing through 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 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.

Okay, 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 when this means to our Alaska operations. First of all, as you see on the right, these are logs of our producing horizons. Moraine is a large stratographic trap of thinly laminated sands that sit some 1,000-feet above, let's say, the Kuparuk reservoir. They're about 200 feet thick. We expect there to be in the neighborhood of 50 million 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 Exploration wells have been drilled here by others. The significant ones being in the mid 1980's when Texaco was testing oil from vertical fraced 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, on 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 is 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 continuity of the reserves 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 extending the reach drilling from that pad. And so, this is a very interesting development to continue to enhance the value to 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 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 non-opt campaign that's under -- that's being -- going right now with E&I 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.

Great. 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 noncash, 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 Alaskan petroleum production tax credits, in cash, for the quarter. So, we recognized that. And in addition, we did get some insurance money related to our East Cam 322 platform project that happened back in 2005. And we still expect, in the future, substantial insurance reimbursements as we move forward as well. So netting all of that together, $58 million of adjusted earnings or $0.48 per diluted share. Looking at the bottom of 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 realized prices. You can see from oil prices were essentially flat with the fourth quarter, up 1%. NGL prices continue to move up and they were up 11% compared to the fourth quarter, at $41.82 per barrel. And then, if 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 at the beginning of the quarter and have since fallen back some. So, we would 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 VPP's. Looking at the bottom of this slide, derivative impact included in price, FR, just shows what's the effect of our derivative positions. It's included in the price, as I mentioned in the prices above. Those will continue to decline 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 2009, we're 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, which 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 improvement but we also resumed production in our South African gas project when [Petros] brought back on their GTL plant. It had a low cost average on a production cost basis, since that helped lower our per BOE costs as well.

Turning to slide 18, we put this in just to show on our cash costs compared to our peer group. This is a study that done by Credit Suisse for 2009. You can see that for 2009, we were $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. I think it's important, as we're one of the oilier companies in the peer group, as you guys are aware. And so, we compared 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 structure 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 BOE's per day. Really, reflecting our production growth that we're 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. And so, take a look at those. Also, when you look at slide 20, we do have a number of slides in the back for supplemental information. I'd encourage you to take a look at those when you get a chance. But why don't we stop the call there and we'll open up the call for questions.

(Operator Instructions) And we'll hear from Scott Gill with Simmons and Company.

Hi, guys. Looking at the Spraberry with the addition of the lower shale and silt zones, is a 15% to 20% improvement still what you guys are seeing on those wells? And how is that translated into improving EUR's?

Yes, Scott, this is Tim. I think we can say, definitively, based on the work we did the year before last, that that 15% to 20% number is pretty good. Especially, in consideration of just the shale and silty zones. What we don't yet have, in the main part of our acreage, is the deepest Wolfcamp contribution. Although, we have seen some very encouraging signs that it may add a significant percentage of additional EUR as well. You've just got to give us a little more time to get this drilling campaign finished this year. We'll be able to report a lot more about that through time.

Okay. And then obviously, the improved well performance and the acceleration of the Spraberry a little ahead of schedule. How do you guys feel about your 10% quarter on quarter versus fourth quarter guidance? Is that biased higher at this point?

Yes, go ahead.

I will simply say that we try to be conservative on this guidance and we're trying to overperform.

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

Yes, 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.

Okay. And then, just my last question. It 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 pass the Riedesel #1 well and when could we expect that and what are your expectations out of that area?

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

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 in the Eagle Ford.

It's a question of when we get these six to seven 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.

Okay. Thanks, guys.

And next, we'll hear from Amir Ariff with Stifel Nicolaus.

Hi, guys.

Hi, Amir.

A couple questions. One on the capital costs, just as you guys are adding more rigs and the rest of the industry is adding more rigs to the area too, are you seeing any cost pressures on the 1 million per well that you were assuming?

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

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

Yes, I think what you're looking at here is areas where we have very high quality rock in the Wolfcamp, either in the middle part of the Wolfcamp or the deeper 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 rock. So,we'll have to get back to you with the results but that's the objective.

Okay. And those wells, the first couple horizontals are scheduled for the third quarter?

Yes.

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

It will be roughly about 310,000 gross.

310,000. Are you adding any acreage currently inside or outside of the JV area?

Both.

Both?

Yes.

Okay. Then, just final question in Tunisia. Can you just give the sense of the prospects size for the three non-op wells that you're going to be drilling out there, what you're thinking about?

Yes, they're generally about 2.5 million to 5 million barrels per prospect.

Okay. Thanks, guys.

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

Good morning.

Hi, Mike.

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

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

Are there any key variables that they're keying off of that might help us in thinking about the play as a whole?

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

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

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

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

Yes, our goal is to build to the existing midstream entities, to them. So, we're going to build central gathering facilities. That's why some of our wells, which potentially 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.

Okay and any discussion on CapEx required there?

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

Okay, thanks. And then one last one, if I may. Completion crew availability, I've been hearing of some tightness, particularly in more of the western extent of the play. But how's that looking at this point? And what's the outlook look like from your perspective?

I think it is tight. There's 45 or 50 rigs running but what we've seen, is it really just leads to slight delays. We might have to wait a couple 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 play. We're going to be drilling wells for multi-years but we are looking at a couple of week delays for fracs.

Great. That's all helpful. Appreciate it.

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

Good morning, everyone.

Good morning, Michael. How are you doing?

Doing all right. 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?

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 of those zones now and all of our wells, we need about six more months, at least, before we come out with a new type curve.

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

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 type curve well coming in about 50 barrels a day.

Okay, that's really helpful. And then, looking at your slide ten, you show 700 wells next year. But just kind of doing the simple math of two wells, per rig, per month, if you started up -- 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?

Yes, 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 ten rigs on December 31, 2011. So, at some point in time, we will have increased 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.

Okay. That makes sense. The final question is, I saw some language in the press release about nonoperated activity in Tunisia. I think, before, you were talking about three wells in total. And 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 then, I'll hop off.

Yes, E&I, 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.

Great, thank you.

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

Good morning, guys.

Good morning.

You talked 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? And would you still be at a $1 million cost? I imagine that would go higher if you're adding the Wolfcamp. Just trying to get a sense of some of the costs surrounding adding those zones.

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

Okay. Obviously, you guys have known of the existence of Straughn in the Wolfcamp for quite sometime. Just curious as to kind of why, at this point in time, you're deciding to go out and add the Straughn to a lot of wells? And why the timing is right for horizontal well in the Wolfcamp? Are you seeing other industry players out there with success that you're trying to replicate?

Yes, it's a combination of that but our success over the last two years in the middle Wolfcamp, in the heart of the field has been very successful. So, since we made a decision to open up the middle Wolfcamp's, in all zones, the Wolfcamp is about 1,000 to 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 to open up the lower Wolfcamp. So, we opened up the lower Wolfcamp, tested about 30, 40 wells. Very productive in the lower Wolfcamp, the bottom 200 to 300 feet. So, we made the decision to take every well down to the lower Wolfcamp just recently.

And now, we're doing the same. Since the Straughn is right below the lower Wolfcamp, it turns out that every time we add another 200 feet of pay, it's easy to go to the next 200 feet. And so, Straughn is pretty much -- before you get into some higher pressure Devonian and Fusselman areas, this is about as deep as you can get. We will have to get comingling permits and change the field rules if the Straughn is successful. There's been several Straughn tests by us and by other operators. And so, we're going to see how large of area it is in the Straughn, before we make a decision to take a lot of the wells down to the Straughn.

Okay. Obviously, it looks like you have some initial additional success here in Alaska. Just curious as to what you guys had booked as proved reserves at year end 2009? Trying to get a comparison with that and your 130 million to 150 million-barrel target.

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

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

Well, we've got several years of drilling. I don't know that it will be necessarily two years or three years but over the next several years, we'll be putting in significant reserves.

Okay. Thanks, guys.

Thanks, Leo.

And next, we have Sven Del Pozzo with C.K. Cooper.

Hi, good morning. Do you have enough data yet from your earliest Eagle Ford wells to give us an idea what kind of decline rates you've seen after about a month or so?

Yes, it's still running at about 75% decline rate. So, it's matching pretty much our type curve. The only well that's not matching our type 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 type curve of 6 BCF.

Okay. And, sorry, could you confirm for me again, the 75% decline rate is over what period of time?

That's basically the first month.

Okay.

Year, yes, for the first year, yes.

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?

Year, exactly.

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

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 3D seismic reprocessing, we feel like two of the fields are much bigger and could be several well development projects. And then we're drilling an exploration well up in Anaguid.

Okay. And 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 repressurize the reservoir, should the -- will that 7,500 barrels per day, how long will that be producing at that rate for?

Well, I think the answer is still, as yet, undetermined. I think the larger of those two producers will be the one that's used as an injector. So, it will be a matter of several months before we turn it into an injector.

Okay. All right. Did you mention -- I might have missed it on your comments, did you say that the data room is closed or it's still open, for the Eagle Ford Shale?

It's closed.

It's closed, okay. All right. Thanks, gentlemen.

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

Good morning, guys.

Good morning, Brian.

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

Yes, it's mostly small blocks. I just saw what Forest just picked up 100,000 acres. They announced it. So, it's people -- it's such a -- it's a 250-mile all the way to the border. So, people are buying -- it's pretty -- several from north to south. So, people are still -- Shell just made an announcement. Talisman made an announcement. But 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 $2,000 per acre in that area. And they're mostly small areas.

And you have a pretty aggressive capital budget going forward. Where and when, if ever, in the near term, do you start going after some of the gassier plays, whether it's the Barnett or the Raton? When do you start putting capital there to try to, I know it's shallow decline, but at least, help stem that decline.

Yes, we need to see a $5 gas market or better.

Okay.

And have confidence into it, even though we're hedged. But we need to be confident in a $5 gas market.

Okay. Even in the Barnett?

No, in the Barnett, we're looking at starting a rig up some time in the third or fourth quarter in the liquids-rich area.

Okay, guys. Thank you.

And we'll hear next from Gill Yang from Banc of America-Merrill Lynch.

Good morning, everyone.

Good morning, Gil.

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

That will be a new drill.

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

Yes.

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

The current plan, Gil, is to drill the first of these wells in the lower Wolfcamp but probably the second would be 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.

Okay. The Wolfcamp is sort of the ideal zone, in general, to drill into because it's not been vertically penetrated quite as much because of the other zones above it?

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

Okay, all right. When the waterflood gets going, as 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 to have that benefit?

Yes, it's not nearly big enough to impact the overall scale of our LOE. It's only 7,000 plus acres. And so, if you put that in the context of a 900,000-acre position, you can see, we can lower operating costs there 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 every day out in the Permian Basin, we produce four barrels of water or so for every barrel of oil. And so, this is a low cost way to, in essence, reinject water that would otherwise have to be disposed. So, in actuality, it will give us a very good advantage in this kind of project because we get the cost savings.

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

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

Okay. And the lifting costs for the waterflood production itself, is that different from the lifting costs in isolation, except for the water issues, are those lifting costs similar to other Spraberry production?

Yes, they'll be identical.

Okay. 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?

Well, these are high productivity wells, very excellent quality sands. We've seen wells with IP's up to 7,000 barrels a day, 7,500 barrels a day in the Kuparuk. And so, it's not unusual to have this high quality of results out of the Kuparuk and the wells typically produce at relatively high quantities for a long time. 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.

Okay. So, we should see a substantial pickup in the volumes coming out of Oooguruk because of these wells?

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 converted into an injector. Overall, production will be up about 60% to 70% on a year to year basis, counting all the sources including Moraine.

All right, great. Thanks a lot.

You're welcome.

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

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

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