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Pioneer Natural Resources Co. (NYSE:PXD)

Q3 2009 Earnings Call

November 4, 2009 10:00 AM ET

Executives

Scott D. Sheffield - Chairman and Chief Executive Officer

Timothy L. Dove - President and Chief Operating Officer

Richard P. Dealy - Executive Vice President and Chief Financial Officer

Frank Hopkins - Vice President of Investor Relations.

Analysts

Michael Jacobs - Tudor, Pickering, Holt & Co.

David Kistler - Simmons & Company

Brian Singer - Goldman Sachs

Robert Christensen - Buckingham Research Group

Joseph Allman - J.P. Morgan

Leo Mariani - RBC Capital Markets

Operator

Welcome to the Pioneer Natural Resources third 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, then select Investor Presentations.

The company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements.

These risks and uncertainties are described in Pioneer's new release, on page two of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.

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 is going to be up first. He will review the financial and operating highlights from the third quarter.

He will then comment on the outlook for remainder of 2009 and talk about some of the early thinking about 2010 and 2011. After Scott concludes his remarks, Tim is going to give you an update on drilling plans for the Spraberry, the Eagle Ford Shale, Tunisia, and Alaska.

Rich will then cover the third quarter financials in more detail and he will provide earning guidance for the fourth quarter and after that we will open up the call for your questions.

So with that we'll get started, I'll turn the call over to Scott.

Scott Sheffield

Thanks Frank and good morning. We appreciated the time for people to listen in. I'm at slide #3 on highlights. For the third quarter, we adjusted net income of about $3 million or $0.02 per share and that excludes mark to market loss of about $10 million or $0.08 per share.

Also includes a net gain primarily from the sale of our Gulf of Mexico shelf properties totaling about $5 million after tax or about $0.05 per share.

Production was above the mid point of our guidance, at 113,000 barrels oil equivalent per day, up 2% versus third quarter of '08 and up 7% year-to-date nine months of '08 to nine months of 2009.

I think the most important thing of this call are the next two items in regard to -- we have announced and began aggressively putting together an aggressive Spraberry drilling program to get to at least 1000 wells by 2012, starting aggressively again with costs significantly down of 30% plus.

Returns up significantly for crude prices with their additional hedges we have already contracted most of the rigs. We are getting most of (inaudible) pipe for the next years and tubulars to really ramp up Spraberry production. Tim will give a more detailed report on that, but the goal will be double production over the next four years by 2013.

Secondly, we have a very successful Eagle Ford Shale with IP of about 11.3 million a day, very rich in both condensate and also natural gas liquids with about 1200 Btu gas. We have about 50,000 acres and it's an immediate area we feel like we'll perform, similar to this result, we are now drilling our second well, which Tim will talk more about.

In addition we'll also talk more about later on about exploring a JV strategy to accelerate the Eagle Ford potential, much more than we're showing in our CapEx over the next several quarter.

We reduced production cost per BOE by 24% versus the third quarter of '08 in response to all of our cost reductions initiatives. Production costs were up this quarter primarily due to the major reason was higher oil prices, which we end up paying higher severance taxes.

Then regard to protecting our cash flow with upside, we've added more derivatives over the last three months on both oil and gas. We're now up to 85% in 2010 and a 11 in gas production 80% covered in 2010 and 50% in 2011, we'll talk more about with our rainbow charts on our estimate of cash flow over the next two years.

Also important we've obtained our debt reduction targets of hitting $2.7 billion net to PXD, we reduced debt by $250 million during the third quarter, combination of our PXD drop down, the sale of Gulf of Mexico Shale properties and free cash flow during the quarter.

Turning to slide number 4, we continuing to deliver consistent production per share growth, again we came about it was about 5% production per share plus versus 2008 about ramping down activity, we're still going to be achieving that target.

And obviously with our big ramp up in activity especially in the Spraberry in Alaska in all of our oil plays, we'll be returning to quarterly production growth in the first quarter of 2010.

Slide number 5, on our cash flow and CapEx, we currently expect about a billion right now, if you look on the strip we're closer to $1.1 billion between a billion and $1.1 billion of operating cash flow in 2010. We got a range of $850 to $1.3 billion of cash flow.

The 1.3 is achieved to hitting the upside of our targets of $84 and $8 in Mcf but what's interesting, we can live easily with a $4 gas market as we saw in 2009 for 2010 and a $75 crude market and it wouldn’t effect, we would still be growing on a quarterly basis and generating free cash flow.

So primarily due to the hedges that we have put in place and much higher prices allowing upside. Also we've increased our Capex as we have noted in the last quarter. We said we’re looking to accelerating Spraberry even more so during 2010.

So if you noticed we bumped up our $750 million up to $900. That’s primarily due to another $125 million for Spraberry and a little bit more by continuing our Eagle Ford well rig during 2010.

We are obviously 90% all focused. If you consider the Eagle Ford oil play, we’re essentially 100% all focused moving forward. Lower end of range includes 425 Spraberry wells, obviously with a rig in Alaska, three wells in Tunisia and our Eagle Ford Shale play.

Also obviously there is still a big risk to what may happen in natural gas prices in 2010. We've stated of the last several weeks and quarters, we want be confident that we’re going to see $5 gas plus even though we’re hedged.

We think it’s important to look at the economics of your new production, which is generally not hedged in most companies, to make sure we get good returns for our investment. So we’re waiting to see how gas ends up in regard to this winter and also what happens with storage.

Turning to slide number 6. Going out to 2011. I think the most important thing with our hedges and our upside; we pretty much have locked in a cash flow of $1.4 billion with upside to $1.8 billion with our three ways hedges in regard to both gas and oil.

This will allow us to continue to ramp up, as Tim will talk about adding another 250 to 300 wells, Spraberry primarily in 2011 taking that total of 700 wells in the Spraberry Trend area program.

Slide number 7, in regard to our rig count schedule; obviously we're focused from regard to the Spraberry, Alaska, and Tunisia. We will be starting off strong quarterly production growth in first quarter of 2010 and ending strong at the end of 2010 obviously most of the focus on the Spraberry Trend area.

One rig in Alaska, one in Tunisia and one in Eagle Ford shale, as we continue to explore for a JV to accelerate development, obviously with further success the rig count can increase significantly in the Eagle Ford shale program.

Last slide, why invest in PXD, obviously we have a large drilling inventory and resource potential with over greater than 60% oil, obviously if we had Eagle Ford in there it will be over a much higher number too.

We are accelerating over the next several years getting up to 40 rigs 1000 wells plus about 2012 and with Spraberry Trend area, we'll continue that program for several years, obviously we are very excited about our Eagle Ford shale well and looking forward to more success in that play.

We got attractive derivative positions to protect you in top or downturn in regard to commodity prices, but with upside in 2010 and 2011, over the next several quarters we'll also luring in three way hedges in regard to 2012. We think it's very important to deliver free cash flow. We did it in 2009; we’ll do it in 2010.

We have very strong and improving financial flexibility. Obviously with our cost cutting and margins are improving significantly and obviously we have this low decline base that delivers very, very stable cash flow.

Let me turn it to over to Tim to go over operational reports.

Timothy L. Dove

Thanks Scott and just in the last quarter, my plan is in the next few slides to give you update on the operational areas we have current activity. So we’ll start with the Spraberry Tend area.

In fact Slide 9, the attempt there is to frame up the type of impact that Spraberry can have on Pioneer’s growth plan as we resume a significant drilling program. As you can see on the slide, the Spraberry Trend area is the large onshore oil field in the lower 48 states.

And that means because of our essentially 50% share of that field, it has substantial impact in terms of future growth potential and because of our position the field has the largest operators you see on the right hand set of bars.

We’re larger than the next four operators combined, which means as we look forward, we’ll have a lot of control of our own destiny in terms of growth. I’ll talk more about that on the next slide.

But sufficed to say with 910,000 gross acres under lease, with about 75% of those held by production, we have a very significant acreage advantage in the field and planned to use that to ramp up the drilling campaign as we’ll talk about significantly on the next slide.

The key to all that of course is bringing forward the PV of this field and of course it’s a tremendous resource and the objective of all of our activities is to increase recovery rates going forward.

Slide 10, the next slide on Spraberry really is focused on the operational results. We've seen a consistent growth in the field. It’s grown about 8% this year compared to the first nine months of ’08, really reflecting last year’s drilling campaign 2008 as well as some benefits that were delayed until the first quarter of 2009 regarding the NGL benefits.

But overall the field exhibits very low decline rates, which is good in the situation we've had in 2009 we have done a limited amount of drilling.

We are going to substantially ramp our drilling next year 2010, the current campaign calls for about 420 wells, as Scott has already mentioned many of the rigs in fact most of the rigs that we have planned for next year already contracted.

We will start the year with about 14 rigs going to 19 in the middle part of the year, 24 at the end of the year, the idea being ramping continuously into 2011 and 12, a drilling campaign that could really seriously move the company's metrics.

Most of those wells will be deepened into the Wolfcamp in fact only about 50 wells will not those would be the wells we drilled in the water flood area and in most cases of course based on the activities over the last couple of years we'll be completing wells in the non-traditional shale silt intervals that are proven to be very successful adding production and reserves at the margin in all these wells.

It's the case with oil prices is doing as well as they have over the last few months that we have excellent returns in excess of 50% before tax based on today's pricing and the fact that well cost have come down substantially.

I think if you look at our campaign in drilling in 2010, you'll find that, on average our wells would be approximately $1 million, we'll have some it will be slightly less than a $1 million some will be slightly over, but overall we calculated an average of about $1 million per well for those 425 wells planned for next year.

And as the result of the fact we've done a great job I feel like in reducing the well cost for that campaign.

We are implementing the waterflood it will be implemented to a greater extent in the first half of 2010. We anticipate the impact from the water flood will not be seen for some 6 to 9 months after that.

So very late 2010 perhaps into 2011. The effort of course again is to increase recovery rates in every field – in every area of the field we have activity.

On slide 11, this is an important slide reflecting on the kind of impact that a Spraberry development campaign can have on both the metrics in that field, but also overall corporate metrics.

If you look at 2009, you can see we've been on a slight decline, actually the first quarter is with 37,000 barrels a day shown, it was impacted by NGLs being deferred into that quarter from the prior year.

But if you look at the decline rates in 2009, you'll see we’ll be declining to the end of this year, and then as we start drilling again, ramping up an increase quarter-by-quarter in 2010.

If you look at this 2009 and 2010 will be essentially flat on a year-on-year basis. But we’re growing substantially from fourth quarter this year to fourth quarter next year owing to that drilling campaign.

If you look forward, and as Scott has alluded to, if you go past the 425 wells in 2010, go to some 700 wells in 2011 and then 1,000 wells plus perhaps 2012 and 2013, you can see it’s very easy for us to calculate reaching a production CAGR of approximately 20% through 2013 with production doubling by that time.

All of these numbers shown here do not include the impact of the pending waterflood project as planned for 2010 nor any future waterflood projects. So I think there is even upside above what these numbers show.

But needless to say, this type of growth, this type of drilling campaign and the results therefrom, should have a very positive substantial impact on Pioneer, all of our metrics including production, cash flow growth et cetera.

So we’re really excited about getting back to drilling after what's been a slow drilling year, 2009. Slide 12 is, and a couple of slides thereafter are some details surrounding the Eagle Ford Shale expansion. We’re extremely excited about the recent well results from the Sinor #5.

As Scott has already mentioned, this well IPed at substantial rates, 11.3 million cubic feet per day equivalent and importantly had a large component of both condensate and NGL such that we can calculate that about 55% of the production is essentially liquids and only about 45% gas.

We were somewhat limited on the extent of the lateral section of this well to only 2,600 feet. We’ll be increasing that as we look forward to future wells. Importantly, we had originally planned about a five well program as we embarked upon our Eagle Ford Shale development.

Now we’re planning to keep that one rig at a minimum growing all the way through 2010 to assess the resource potential in various areas of the field with one of the main objectives being to increase the length of laterals and increase potentially the number of frac stages.

And toward that end we have our second well drilling. It’s shown as the second – the southern most of the two red stars below the Sinor well. This well is about 2.5 miles away from the Sinor well. We’re starting as we speak to drill the horizontal section here shortly. It will itself have about 4,600-foot lateral and the plan is for 16 stages of fracs to be pumped.

And so we’re very much looking forward to this well as the second of several wells looking forward. We’ll have to evaluate a further program expansion as we look the results of this well and additional wells to decide whether to increase the rig count in the play.

As Scott has already alluded to we think there is benefit associated with exploring joint ventures opportunities. We've got a lot of acreage here, the objective is to accelerate the development of that acreage in the Eagle Ford and we think a joint venture could potentially do just that.

Importantly as we return to slide 13, the liquids components of this first well is indicative of potential significant value added when it comes to the economics of these wells, especially based on today's commodity price model where you have based on today's nearby strip prices something like 16 to 1, oil to gas ratio.

So if I were to calculate then the type of impact from the liquids just using the IP of the Sinor #1 well, Sinor #5 well is an example, you would take a dry gas well of the similar volume 11.3 million a day, $5 gas and achieve about $57,000 per day revenue.

If we then compute the amount of revenue that's generated from the Sinor # 5 well, giving consideration to let's say $70 condensate, NGL price is about 50% of that and the remaining dry gas after shrinkage, we would achieve some $96,000 a day of revenue, about a 68% increase compared to the revenue from the dry gas well.

So you can see the very significant impact of a combination of condensate and 1,200 Btu gas on the economics of these wells. And another way to think about it is liquids rich Eagle Ford well with 11.3 million cubic feet a day equivalent IP would have essentially the same revenue as if we had a drilled a dry gas well with about 19 million cubic feet a day dry gas IP.

So it's clear that the liquids content is going to continue to be a critical component in the overall economics and maybe one of the keys to the Eagle Ford shale economics being very competitive as compared to several other shale plays.

So obviously we're very excited about the play and its impact on Pioneer going forward and we have lot more to talk about in subsequent quarters as we begin our exploitation of the Eagle Ford shale.

Couple of more slides in other areas, we have operations that are underway. Alaska continues to perform well in terms of productions as shown on slide 14. Production in the third quarter was about 6,000 barrels a day.

We've finished our summer drilling campaign, which typically is involved, with drilling horizontal wells in the Nuiqsut, which is the deeper of the two horizons. We've drilled three producers and two injectors and frac those wells and have a very good success compared to unstimulated wells.

In the wintertime, of course we switch over high rate Kuparuk drilling. So we should have a significant impact on production as a result of our winter drilling campaign.

Importantly in Alaska, we still have substantial resource potential. The vast majority of which is currently un-booked, so it should add potentially pretty significant volumes to reserve as over the next several years.

On slide 15, a slide on Tunisia. We're in the process of contracting a rig to recommence drilling here. The plan is a three well program that would commence probably in January. Overall production is declining in the field as we await the drilling campaign.

There are couple of wells being drilled in non-operated areas particularly in the Adam concession. But our drilling that will recommence in January is based on 3-D seismic this been shot and processed recently in both the Anaguid and Cherouq areas and those three prospects that will be drilled shortly it's beginning in January are important in terms of evaluating their impact on future production increases as we looked 2010.

So I'm sufficed to say our operations are performing well, we got a lot of new and interesting things going on.

With that, I'll pass it to Rich for a review of the third quarter financials and his outlook for the fourth quarter.

Richard Dealy

Great, thanks Tim. Turning to slide 16, earnings summary. For the quarter, we are reporting a net loss attributable to common stockholders of $7 million or $0.06 per share. That did include mark-to-market derivative loss non-cash of $10 million after tax or $0.08.

So adjusting for that mark-to-market loss as Scott mentioned, we had a $3 million of income or $0.02 per share.

This quarter did include a couple of unusual items. The biggest one being the gain recognized on the Gulf of Mexico Shelf sale that we talked in last quarter's call that was $12 million after tax or $0.11.

Also in the quarter we had a charge of $6 million or about $0.05 per share related to staked rig charges. That's down significantly from prior quarters and we expect it to continue to fall down as we either, those contracts have expired or two, if the rigs are put back to work.

Looking at the bottom of the slide, production guidance relative to results for the third quarter. Basically we were in guidance on virtually all of the items with the exception that Scott mentioned, production cost where we are above guidance.

A big chunk of that is attributable to higher production taxes related to higher oil prices. And I've got a slide we can go over that more detail. Exploration abandonments were at the top of the range, principally due to some non-cash acreage charges that we took for acreage we are not renewing.

Looking at non-controlling interest that's related to Pioneer South with Energy Partners or MLP the above guidance amount and the results being above guidance there really non-cash mark-to-market on derivates held by PSE.

And then cash taxes were slightly above guidance mainly primarily to Tunisia cash taxes for the quarter.

Turning to slide 17, price realizations. You can see in the green bars there, the oil price realizations were up about 10% relative to the second quarter, falling along with the rise in oil prices that we saw on an NYMEX basis. NGL, similarly we are up 24% quarter-on-quarter to $33.13 per barrel and gas prices were up 6% quarter-on-quarter.

On a first blush, a little surprising, because NYMEX prices from a bid-week standpoint, were actually down quarter-on-quarter, but we did see a significant basis narrowing during the quarter. So, our price utilizations were up.

At the bottom of that slide, I've included in the first horizontal bar there, the derivative impact that’s included in price that reflects everything that was -- hedges we had in place prior to discontinuing hedge accounting on February 1 of this year.

While the bottom bar reflects the cash settlements of any derivatives that have been not included in pricing during the quarter for changes in fair value since February 1 or new derivatives put on and have settled.

Turning to slide 18, looking at production cost, you can see year-over-year substantial decrease about 24%. The asset teams have done a fantastic job of really bringing down base LOE.

As you can see, most of that has been driven by reduced water disposal and water hauling cost, facilities and infrastructure improvements, power and fuel cost coming down relative to commodity prices coming down.

We've optimized our compression throughout our gas fields and we've continued to add to our well servicing capabilities, doing more of that work in the Spraberry area, we already had it in the Raton area. So, basically there was a big decrease in production cost year-on-year.

Looking at the second quarter relative to the third quarter, we are up about 11%. It's primarily driven by production taxes as we talked about before with the higher oil prices. Also work-over costs were up slightly and then on the base LOE side, you can see that we began some preventative maintenance in the third quarter, which has caused a slight increase.

I think the most important point though relative to this is that we have not seen any cost inflation in our underlying operating costs from other service providers, those have held constant quarter-on-quarter and that’s the good news relative to this slide.

Switching gears look at fourth quarter guidance on page 19, daily production as we forecasted last quarter for the fourth quarter is 105,000 to 110,000 BOEs per day. This will be the low point for the Company as we expect to resume production growth quarterly next year as both Scott and Tim have talked about.

The fourth quarter being down relatively to the third quarter. It is primarily associated with our South Africa plant turnaround that is happening there which PetroSA is doing, so we’ve been – production has been down. South Africa production should be resuming here in early November and so that will be coming back online.

Also, as Tim talked about, we are in a natural production decline to do the reduced drilling that we have had going on during 2009. And so that will obviously turn the corner here as we move into 2010.

Production costs per BOE slightly higher than they have been prior quarters, really reflecting higher production taxes, relatively higher commodity prices, with lower production volumes that we’ve talked about and then increased workover activity on oil projects as some of those projects make good economic sense to start performing now where oil are at.

Exploration and abandonment is $20 million to $30 million for the fourth quarter, DD&A expect to be $15.50 to $17 per BOE, really reflecting the new – or expectation of the new SEC rules relative to pricing methodology will be enacted during the fourth quarter and that will have the effect of switching from using quarter-end prices to calculated reserves to a 12-month average versus first the day of each month.

And so based on our estimate today, we expect oil prices to be about $62 per barrel to average for the year using that methodology and $4 per Mcf for gas.

And so that will have the result when you look at third quarter relative to fourth quarter of losing some tail reserves due to lower commodity prices and causing our depletion rate to move up slightly.

G&A and interest expense consistent with prior quarters, rig stack exact charges we've talked about, have continued to come down at $5 million to $10 million and then the remaining items here consistent with prior quarters.

So with that, we'll open up the call for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question comes from Michael Jacobs - Tudor, Pickering, Holt & Co.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Quick modeling question, I think investors were a little bit spooked with the increase in cost this quarter and I know you talked about a little bit in your commentary and the presentation about higher workover and production tax.

Can you peel back the onion a little bit more and discuss where you saw higher operating costs and what we should think about as recurring versus non-recurring in the context of maintenance versus servicing?

Timothy L. Dove

Yeah, 40% plus was severance taxes and 3% to 4% was just production declines coming of the last quarter. And so we really saw no pick at all in regard to – there's some workovers obviously in Spraberry, some other areas, but those were the major factors.

So with increased volumes going into 2010, we should definitely see production operating cost come back down.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Tim I think you mentioned this earlier, but how much of your 2011 to 2012 Spraberry guidance comes from the waterflood program?

Timothy L. Dove

There is no waterflood volumes in there.

Michael Jacobs - Tudor, Pickering, Holt & Co.

On your JV commentary the Spraberry ramp is generating some pretty nice free cash in 2011 plus how do you think about using that cash to accelerate the Eagle Ford whether it would be in Live Oak or the Dewitt area?

Timothy L. Dove

I would look at it like a Spraberry it's going to build on itself in regard to just for ramping up Spraberry, it may or may not have a lot of free cash flows into ramping it up to a 1000, it will start generating significant free cash flow in 2012 and beyond.

And we will take some of our long life gas assets that will be having free cash flow and using some of that to accelerate the Eagle Ford play along with a possible JV, so.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Did you guys take a look at the swift assets and so why didn't you get involved?

Timothy L. Dove

We have a policy Michael not to comment on what data rooms we go into. So obviously if you look at, Tim made a comment on this, but if you look at our acreage map, we have extended acreage buying into McMillan County, which is where the swift acreage is.

So obviously it's very, it's close to our acreage. So but just can't comment on what data rooms we go into.

Michael Jacobs - Tudor, Pickering, Holt & Co.

One last question on (inaudible) if we assume best case results from the Eagle Ford, which hope might get into to a development case, would that increase your willingness or your desire to sell international assets?

Timothy L. Dove

We always look at different ways to come up with capital in regard to accelerating obviously the first one will be in regard to JV strategies over looking at with a lot a people are very excited about the Eagle Ford Shale and Petrohawk stating it is good or better than the Haynesville.

And with the oil richness of it that obviously that’s number one but obviously we are always open to looking in other ways to raise capital to accelerate Spraberry and also the Eagle Ford play.

Operator

Your next question comes from David Kistler - Simmons & Company

David Kistler - Simmons & Company

Real quickly on the Spraberry and your rig plan going forward. Can you talk a little bit about what portion of that you've contracted already? And then from a standpoint of returns, at what prices you might consider not accelerating quite so rapidly just because IRR gets impacted obviously today not an issue whatsoever.

But thinking about it as you are kind of moving over the next really three years that you've outlined for us?

Scott Sheffield

Dave, we've got, as I mentioned in my commentary about 19 rigs already contracted essentially that appears through the rigs we need for the period of January through July. If we want to hit 24, we got a few more to add by the end of next year.

In regard to the fact we went through a large build in preparation for a large 2009 drilling campaign, we've got lot of inventory pipe, pumping units and so on. So we actually are well prepared to meet all of the needs from a inventory standpoint or our capital items into 2010 program.

Right now we are actually contracting 2011's program. So we are well on the way to being well prepared for even 700 wells in 2011 as we speak.

David Kistler - Simmons & Company

Okay that's helpful. And then just talking about CapEx for a second, if you look at what you guys been thrown out as your potential budget going forward, there's obviously an opportunity throw off free cash flow tying that to your comments on looking at a JV structure for the Eagle Ford to accelerate drilling there.

Do you think about deploying that gap of free cash flows straight to the Eagle Ford and accelerating that on your own? I guess the gist of the question is does the CapEx number that you throw out have a bias upwards potentially?

Scott Sheffield

Obviously, we need to see some more results. We're watching activity all around our acreage. There's over 20 rigs running now and the Eagle Ford is picking up significantly. And so we're getting reports on all of the wells that lot of our acreage being tested on the outside parameters at the same time we are testing it internally.

So the more data we get the more of comments we have, we will definitely be accelerating in spending that. But at same time I think it's important to deliver free cash flow under any model that we go forward at the same time we need more data to accelerate greatly the Eagle Ford play.

David Kistler - Simmons & Company

Okay that's helpful. Hop into Alaska for a second. Last quarter, you guys have talked about establishing some redundancy for the water supply and potentially investing in that.

Any updates with respect to that obviously that didn't appear to be an immediate issue but was curious where you guys are on that development side?

Scott Sheffield

Yes, we have now incorporated that in our 2010 capital budget, it's not a significant amount of dollars, but needless to say the objective is to become self sufficient on water and that project will be commencing early part of 2010.

Operator

Your next question comes from Brian Singer - Goldman Sachs.

Brian Singer - Goldman Sachs

You mentioned I think, a, that free cash flow is important and, b that, if you do get stronger results at the Eagle Ford that you would accelerate, how do you marry those two together?

Are there some areas where you are spending capital that if the Eagle Ford results were positive you would reduce activity or I guess – how should we think about cash flow versus CapEx?

Richard Dealy

Yes, right now if you look at our CapEx, it's $800 million to $900 million. We are up to $800 million. We haven't decided whether or not to start drilling in the Raton, Edwards and the Barnett shale.

That's roughly $100 million plus in those three areas. So, with the strip at $1.1 billion we are closer to $1.1 billion and a $1 billion, we have about $300 million in excess cash flow. So we have choices depending on where natural gas prices go.

We can move into the Eagle Ford, but obviously we looked at the benchmark, which is very close to our acreage, and the swift they went for 3000 plus an acre. So it's established a new benchmark in regard to that play.

If you look at the potential of a JV strategy and the opportunities then obviously that helps in regard to, it's not a free cash flow issue depending on, if we can explore and close the deal in the next several months that would help us significantly in regard to accelerating the Eagle Ford without dipping into and still have free cash flow.

Brian Singer - Goldman Sachs

Secondly on, can you talk a little bit, little more about reserves and maybe it's a little bit of an unfair question since the rules are changing, but I guess, a, how should we think about reserves for the year, b, as you accelerate Spraberry.

How should we think about the drilling that would come from, just drilling PUD's versus creating or drilling probables and then maybe put in the context to the allegoric results and any additional reserve potential there?

Scott Sheffield

Yes, just taking off Rich’s comments, which is the rules have to be finalized yet. I think you are going to see even though we are going to have some upward price provisions due to oil from last year, but the average price looks like its going to be close to 62 and forward for most companies.

And so gas, I think within the high $5, 5.80, 5.90, last year. A lot of companies should have negative price revisions in regard to gas and upward price revisions for people like ourselves on oil.

In regard to moving forward, obviously if companies with resource plays like the Spraberry and Eagle Ford are going to have lot of flexibility in regard to your booking practice and we haven’t decided yet, how we are going to manage that over the next several years.

Operator

Your next question comes from Robert Christensen - Buckingham Research Group.

Robert Christensen - Buckingham Research Group

Is the geology in the Eagle Ford shale something that causes you guys to take this sort of go-slow approach, wait-and-see, watch-and-see? Is there something more complicated here that I just can't both believe that you are going to run only one rig? What is slowing you?

Timothy L. Dove

What is slowing us Bob? I guess we are little bit more conservative than our peers. I mean, so far the data points are very positive and we are stepping out. Our third well, I think it's shown on the map.

We were stepping out a good, back to the middle of the trend. We are putting some of our wells in the oil window. We are putting some of our wells in the gas gunner segment and we’re putting some of our wells in the gas window. So we are looking at all aspects of our acreage.

We just want to be more careful instead of jumping up to 3 to 5 rigs like some of our peers are doing with very little production there. So give us about six months and bring in a potential JV partner and I think you will see us accelerating it significantly in about six months.

Robert Christensen - Buckingham Research Group

Because we all see these fabulous IP's, so you have reservations about how these well will hold up and you like to see how the industry wells hold up before getting over a log on this thing, is that correct?

Scott Sheffield

No our well is performing exactly like Petrohawk’s wells in the average of the first three weeks of data. So I don’t want to make decisions on allocating huge amounts of capital in a low gas price market and only having two to three weeks of production data.

Operator

Your next question comes from Joe Allman - J.P. Morgan.

Joseph Allman - J.P. Morgan

In terms of the Eagle Ford Shale JV, I know it's early on, what stage are you at this point and if you really haven’t really started, what are the next steps there and what's the timetable on your view and are you willing to sow up to 50% interest in the JV?

Scott Sheffield

Those are a lot of questions. I’ll comment on the timetable maybe by the end of the first quarter, early second quarter of next year. We’re in the middle of the process, so obviously with 310, 000 acres, we are going to be open to lots of ideas, so.

Joseph Allman - J.P. Morgan

And then in terms of just a different topic on the waterflood in the Spraberry area, in that 7,000 acre what's the existing production, what's the current production and then a good waterflood you expect it to get up to what level?

Scott Sheffield

I think the current production and the unit in question where the water flood is going to be done is today only about 800 barrels a day. So it's a relatively small area. It's 7000 plus acres and which is the water flood consideration area.

What we've talked about many time is that the impermeable evidence would show that we would expect approximately 50% bump in the areas where we implement the water flood that would commence some 6 to 9 months after the water flood is implemented.

Joseph Allman - J.P. Morgan

Okay and then assuming a successful water flood there what would be the next step for you guys?

Scott Sheffield

Well I think we've seen a serious of water floods in our operating unit areas, going forward starting 2011, this being considered really a test for us, it's not a pilot project per se is a full scale water flood and we are going to prove to ourselves as to the type of recovery rate increase we get and if that works as we believe it will, then we will launch a serious of these over the next several years.

Operator

Your next question comes from Leo Mariani - RBC Capital Markets.

Leo Mariani - RBC Capital Markets

Sounds like you guys are getting ready to restart your drilling program on Tunisia both on the operated and non-operated site. Give a little more color about the some of those prospects you guys are targeting?

Timothy L. Dove

Yes, obviously the two of them are going to be with reprocess 3D, two pressure wells or two are the bigger prospects that we are seeing a significant production. In fact, two of our best prospects we think they are much bigger in regard to what we initially drilled.

The third well is on Anaguid where we had a discovery last year. So we are excited about all three of them, we should start sometime in late December, or early January, it'll take about 3.5 months.

Leo Mariani - RBC Capital Markets

You just going to have a one operate rig out there and do you think you'll have all the well results in 3.5 months?

Timothy L. Dove

Once we start and 3.5 months from the time we start in January we should have results by April right before earnings in May the first quarter.

Leo Mariani - RBC Capital Markets

I guess [ENI] has also joined a couple of wells. So, those are going to be Frazier Wells or are those more rank explorations?

Timothy L. Dove

They are drilling on two Frazier Wells now as we speak. The fourth quarter and they will probably be drilling more Frazier Wells going into the 2010, but we haven't decided jointly on a budget yet for 2010 with ENI.

Leo Mariani - RBC Capital Markets

Jumping over to Alaska, just so I kind of understood some of your commentary properly in which you had in your press release. Are you guys currently drilling or you're taking a bit of a high [end] out there with the rig?

Timothy L. Dove

We are not drilling as we speak, as we mentioned, we have completed our Nuiqsut drilling. We are doing some proprietary work for some completions in early 2010 and we'll ramping up the drilling here in terms of the shallow [cup sea] drilling as soon as we have freeze.

We need to have frozen, a frozen scenario before we can drill those wells, because they have the potential to flow to surface as an Alaskan rule. So, we're waiting on the freeze up and we'll be back to drilling.

Leo Mariani - RBC Capital Markets

Just kind of curious as to how you think about your production out there, I mean it looks like you had a really nice ramp up into the second half of 2009, where could we expect to be in another 12 months as we get into kind of the last half of 2010 with your volumes?

Timothy L. Dove

I think with our ramp up we're going to somewhere up closer to 10% from fourth quarter '09 to fourth quarter '010 and then going into 2011 with our aggressive Spraberry program in Alaska. Without any Eagle for potential accelerating, we're targeting 10% double digit production growth plus from 2011 on.

Leo Mariani - RBC Capital Markets

I guess I was particularly curious as to what you thought here Alaska volumes would do kind of over that similar period fourth quarter '09 and forth quarter '10.

Timothy L. Dove

We will continue to ramp up significantly over the next two years with both Kuparuk and Nuiqsut drilling.

Operator

There are no further questions at this time. I'll turn the conference over to our presenters for any additional closing remarks.

Scott Sheffield

Again, we appreciate everybody listening into the call and taking the time. Regarding further questions, please give us a call Frank and his group. Look forward to seeing you all the next quarter.

Operator

That does conclude today's conference. Thank you for your participation.

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