先鋒自然資源 (PXD) 2009 Q3 法說會逐字稿

Welcome to 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 Power Point 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 and 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 introduction, 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. Let me briefly go over the agenda for today's call. Scott's going to be up first. He'll review the financial and operating highlights from the third quarter. He'll then comment on the outlook for 2000 -- remainder of 2009 and talk about some of the early thinking about 2010, 2011. After Scott concludes his remarks, Tim's 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'll provide earnings guidance for the fourth quarter and after that, we'll open up the call for your questions. So with that, we'll get started. I'll turn the call over to Scott.

Thanks, Frank. Good morning. We appreciate the time for people to listen in. I'm on slide number three on highlights. For the third quarter, we had adjusted net income of about $3 million or $0.02 per share and that excludes a 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 midpoint of our guidance, about 113,000 barrels of oil equivalent per day, up 2% versus third quarter of '08 and up 7% year-to-date from nine months of '08 to nine months of 2009.

I think the most important thing in 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 1,000 wells, by 2012, starting aggressively again with costs significantly down 30% plus, returns up significantly, crude prices with their additional hedges. We have already contracted most of the rigs. We're getting most of the pipe for the next two years and tubulars to really ramp up Spraberry production. Tim will give a more detailed report on that, but the goal would be the double production over the next four years, by 2013.

Secondly, we had a he very successful Eagle Ford Shale well IP, about 11.3 million a day, very rich in both condensate and also in natural gas liquids with about 1200 BTU gas. We have about 50,000 acres in this immediate area. We feel like we'll perform similar to this result. We're 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 quarters. We reduced production costs per BOE by 24% versus the third quarter of '08 in response to all of our cost reduction initiatives. Production costs were up this quarter, primarily due to the major reason was higher oil prices, which we ended up paying higher severance taxes.

In 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 2011 in gas production and 80% covered in 2010 and 50% in 2011 and 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, a combination of our PSE drop down to sell the Gulf of Mexico shelf properties and free cash flow during the quarter. Turning to Slide number four, we're continuing to deliver consistent production per share growth. Again, we came out with about 5% production per share, plus versus 2008 by 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 and Alaska and all of our oil plays, we'll be returning to quarterly production growth in the first quarter of 2010.

Slide number five on our cash flow and CapEx, we currently expect about $1 billion right now. As we look strip, we're closer to $1.1 billion, between $1 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 billion is achieved hitting the upside of our targets of $84 and $8 an Mcf. What's interesting, we could live easily with a $4 gas market as we saw in 2009, for 2010 and a $75 crude market, and it wouldn't affect -- 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 at much higher prices and allowing upside. Also, we've increased our CapEx as we have noted in the last quarter.

We said we're looking at accelerating Spraberry even more so during 2010. So if you notice, we bumped up our $750 million up to $800 million, $900 million. 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% oil-focused. If you consider the Eagle Ford an oil play, we're essentially 100% oil-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's still a big risk to what may happen in natural gas prices in 2010. We've stated for the last several weeks and quarters we want to 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 investment. So we're waiting to see how gas ends up in regard to this winter. Also, what happens with storage.

Turning to slide number six, going out to 2011, I think the most important thing is 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-way 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 it up to over 700 wells in the Spraberry trend area program. Slide number seven, in regard to our rig count schedule, obviously, we're focused in regard the Spraberry, Alaska and Tunisia. We'll 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 could 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 you add Eagle Ford in there, it will be over a much higher number, too. We're accelerating over the next several years, getting up to 40 rigs, 2,000 wells plus by 2012 in the Spraberry trend area, we'll continue that program for several years. Obviously, we're very excited about our Eagle Ford Shale well and looking forward to more success in that play. We've got attractive derivative positions to protect you on any type of downturn in regard to commodity prices, but with upside in 2010 and 2011. Over the next several quarters, we'll be also layering 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 improving significantly and obviously, we have this low decline base that delivers very, very stable cash flow. Let me turn it over to Tim to go over operational reports.

Thanks, Scott. And just as I did last quarter, my plan is in the next few slides to give you update on the operational areas that we have current activity. So we'll start with the Spraberry trend area.

In fact, slide nine,, the intent there is to frame up the type of impact the 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 largest onshore oil field in the lower 48 states. And that means that because of our essentially 50% share of that field, have substantial impact in terms of future growth potential. And because of our position in the field as the largest operator, as 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 over our own destiny in terms of growth. I'll talk more about that on the next slide. But suffice it 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 plan to use that to ramp up the drilling campaign, as we'll talk about significantly on the next slide. The key to all of 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 operating 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 various load decline rates, which is good in a situation we've had in 2009 where we've done a limited amount of drilling. We are going to substantially ramp up drilling next year, 2010. The current campaign calls for about 425 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 where we'll start the year with about 14 rigs going to 19 in the middle part of the year, 24 at the end of the year and the idea being ramping continuously into 2011 and 2012 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 were not. Those will be the wells drilled in the water flood area and then in most cases, of course, based on the activities over the last couple years, we'll be completing wells in the nontraditional shale silt intervals that have proven to be very successful adding production and reserves at the margin in all of these wells. It's the case with oil prices 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 costs have come down substantially.

I think if you look at our campaign of drilling in 2010, you'll find that on average, our wells will be approximately $1 million. We'll have some that will be slightly less than a million, some will be slightly over, but overall, we calculate an average of about $1 million per well for those 425 wells planned for next year. And as a result of the fact, we've done a great job, I feel like, in reducing the well costs for that campaign. We are implementing the water flood. It will be implemented to a great extent in the first half of 2010. We anticipate the impact from the water flow will not be seen for some six to nine 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 through 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, you 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 kegger 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 water flood project that's planned for 2010, nor any future water flood projects, so I think there's 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 in 2009.

Page 12, slide 12 is -- and a couple slides thereafter are some details surrounding the Eagle Ford Shale expansion. We're extremely excited about the recent well results from the Sinor number 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 NGLs, 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 as 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 of the -- the southernmost 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 a 4,600-foot lateral and the plan is for 16 stages 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 at 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 venture 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 the joint venture could potentially do just that. Importantly, as we turn to slide 13, the liquids component of these -- of this first well is indicative of a real potential significant value adder 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 number 1 well -- Sinor number 5 well -- you would take a dry gas well of a 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 number 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 a 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 other way to think about it is, I think it was the Rich Eagle Ford well with 11.3 million cubic feet per day equivalent IP would have essentially the same revenue as if we had 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 may be 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. We'll have a lot more to talk about in subsequent quarters as we begin our exploitation of the Eagle Ford Shale.

Couple more slides in other areas we have operations that are underway. Alaska continues to perform well in terms of production, as shown on slide 14. Production in the third quarter was about 6,000 barrels a day. We finished our summer drilling campaign, which typically is involved with drilling horizontal wells in the Nuiqsut, which is the deepest -- deeper of the two Horizons. We've drilled three producers and two injectors and fraced those wells and having very good success compared to unstimulated wells. In the wintertime, of course we quickly switch over to higher 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 unbooked, so it should add potentially pretty significant volumes to reserve adds 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 a couple wells being drilled in non-operated areas, particularly in the Adam concession. But our drilling that will recommence in January is based on 3D seismic that's been shot and processed recently in both the Anaguid and Cherouq areas, and those three prospects that will be drilled shortly beginning in January are important in terms of evaluating their impact on future production increases as we look to 2010.

So suffice it to say, our operations are performing well. We've got a lot of new, interesting things going on. With that, I'll pass it to Rich for review of the third quarter financials and his outlook for the fourth quarter.

Great thanks, Tim. Turning to slide 16 earnings summary, for the quarter reporting a net loss attributable to common stockholders of $7 million, or $0.06 per share. That did include a 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, $3 million of income $0.02 per share. The quarter did include a couple of unusual items, the biggest one being the gain recognized on the Gulf of Mexico shale sale that we talked about 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 stack 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, 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, as Scott mentioned, of production costs where we are above guidance. Big chunk of that's attributable to higher production taxes related to higher oil prices, and I've got a slide to go over that in more detail. Exploration and abandonments were at the top of the range, principally due to some non-cash acreage charges that we took for acreage we're not renewing. Looking at non-controlling interests, that's related to Pioneer Southwest Energy Partners, or MLP, the above guidance amount in the results being above guidance there related to non-cash mark-to-market on derivatives 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 that oil price realizations were up about 10% relative to the second quarter, following along with the rise in oil prices that we saw on an NYMEX basis. NGLs similarly were up 24% quarter-on-quarter to $33.13 per barrel and gas prices were up 6% quarter-on-quarter. That's, on a first blush, would be 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 realizations were up. At the bottom of that slide, I've included the -- 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 discontinued hedge accounting on February 1 of this year, where 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 we put on and have settled.

Turning to slide 18, looking at production costs, you can see year-over-year substantial decrease of about 24%. The asset teams have done a fantastic job of really bringing down base LOE. As you can see, most of that's been driven by reduced water disposal and water hauling cost, facilities and infrastructure improvements, power and fuel costs 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 and -- basically, there's a big decrease in production costs 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 we talked about before with the higher oil prices. Also, workover costs are up slightly. And then on the base LOE side, you can see that we've done some preventive maintenance in the third quarter, which has caused a slight increase. I think the most important point though, relative to this, is 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 to look at fourth quarter guidance, on page 19, daily production, as we forecasted last quarter for the fourth quarter, there's 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 relative to the third quarter as is primarily associated with our South Africa plant turnaround that's happening there that Petrol SA 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've been in natural production decline due to the reduced drilling that we've 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 in prior quarters, really reflecting higher production taxes relative to higher commodity prices, the lower production volumes that we've talked about and then increased workover activity on oil projects as those have -- some of those projects make good economic sense to start performing that with where oil prices are at. Exploration and abandonments at $20 million to $30 million for the fourth quarter, DE&A expected to be $15.50 to $17 per BOE, really reflecting the new -- our expectation that 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 calculate reserves to a 12-month average versus 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 the lower commodity prices, hence causing our depletion rate to move up slightly.

G&A and interest expense consistent with prior quarters, rig stack charges we've talked about are continuing to come down at $5 million to $10 million, and then the remaining are consistent with prior quarters. So with that, we'll open up the call for questions.

(Operator Instructions) We'll take our first question today from Michael Jacobs with Tudor Pickering Holt.

Good morning, everyone.

Good morning, Michael. How are you doing?

Doing well, doing well. Quick modeling question. I think investors were a little bit spooked with the increase in cost this quarter. I know you talked about it a little bit in your commentary and the presentation with 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 is recurring versus non-recurring in context of maintenance versus servicing?

Yes, 40% plus was severance taxes and 3% to 4% was just production declines coming off the last quarter. And so we really saw no pickup at all. In regard to some workovers obviously in Spraberry and some other areas, those are the major factors. So with increased volumes going into 2010, you should -- we should definitely see production operating costs come back down.

Great, thanks. And, Tim, I think you mentioned this earlier, but how much of your 2011 to 2012 Spraberry guidance comes from the water flood program?

There's no water flood volumes in there.

Okay, and on your JV commentary, 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 be in Live Oak or the Duwed area?

I would look at it like Spraberry is going to build on itself in regard to -- since we're ramping up Spraberry, it may or may not have a lot of free cash flow since we're ramping it up to 1,000. It will start generating significant free cash flow in 2012 and beyond. And we will take some of our long-lived gas assets that will be having free cash flow and using some of that to accelerate the Eagle Ford play.

Great, thanks.

Along with the possible JV, so.

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

We, we have a policy, Mike, on not to comment on what data rooms we go into. So obviously, if you look at the -- Tim made a comment on this, but if you look at our acreage map, we have extended acreage buying into McMullen county, which is where the Swift acreage is. So obviously, it's close to our acreage. We just can't comment on what data rooms we go into.

Thank you. One last question and I'll hop off. If we assume best case results from the Eagle Ford, which hope might get into a development case, would that increase your willingness or your desire to sell international assets?

We always look at different ways to come up with capital in regard to accelerating. Obviously, the first one will be in regard to the JV strategy is what we're looking at, which a lot of people are very excited about the Eagle Ford Shale and Petrohawk stating it's as good or better than the Haynesville and with the oil richness of it, that obviously -- that's number one, but obviously, we're always open to looking at other ways to raise capital to accelerate Spraberry and also the Eagle Ford play.

Great, thank you.

Next we'll hear from Dave Kistler with Simmons & Company.

Good morning, guys.

Hey, Dave.

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're kind of moving over the next really three years that you've outlined for us?

Yes, Dave, we've got, as I mentioned in my commentary, about 19 rigs already contracted. Essentially, that will carry us 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 inventory build in preparation for a large 2009 drilling campaign, we've got a lot of inventory pipe pumping units and so on. So we actually are well prepared to meet all the needs from an inventory standpoint, all our capital items into 2010 program. Right now we're actually contracting 2011's program. So we're well on the way to being well prepared for even 700 wells for 2011 as we speak.

Okay, that's, that's helpful. And then just talking about CapEx for a second, if we look at what you guys have been throwing out as your potential budget going forward, there's obviously an opportunity to 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 flow 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?

Obviously, we need to see some more results. We're watching activity all around our acreage. There's over 20 rigs running now on the Eagle Ford. It's picking up significantly. And so we're getting reports on all the wells. So a lot of our acreage is being tested on the outside perimeters at the same time we're testing it internally. So the more data we get, the more confidence we have. We will definitely be accelerating and spending -- but at the same time, we 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.

Okay. That, that's helpful. Hopping to Alaska for a second, last quarter you guys had talked about establishing some redundancy for the water supply and potentially investing in that. Any updates with respect to that? Obviously doesn't appear to be an immediate issue, but was curious where you guys are on that development side.

Yes, we have now incorporated that into 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.

Okay, great. I'll let somebody else hop on. Thanks so much, guys.

Thanks.

Brian Singer with Goldman Sachs has our next question.

Thanks, good morning.

Hey, Brian.

Just a couple follow-ups on a previous one. You mentioned, I think A, that free cash flow is important and B, if you do get strong oil 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 well results were positive, you would reduce activity, or I guess how should we think about cash flow versus CapEx?

Yes, right now, if you look at our CapEx, it's $800 million, $900 million. So we're up to $800 million. We haven't decided whether or not to start drilling in the Raton, Edwards and Barnett Shale. That's roughly $100 million plus in those three areas. So with the strip at $1.1 billion, closer to $1.1 billion than $1 billion, we have about $300 million excess cash flow. So, we have choices, depending on where natural gas prices go. We can move into the Eagle Ford, but obviously, if you look to the benchmark, which is very close to our acreage, the Swift deal went for $3,000 plus an acre, so it's established a new benchmark in regard to that play. And so you look at the potential of the JV strategy and the opportunities and obviously, that helps in regard to -- it's not a free cash flow issue, depending on if we can explore and close the deal 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.

Great, thanks. And then secondly, on -- can you talk a 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 will come from just drilling puds versus creating or drilling probables and then maybe put into context the work results and any additional reserve potential there?

Yes, I think just taking off Rich's comments, the rules haven't been totally finalized yet. I think you're going to see, even though we're going to have some upward price revisions due to oil from last year, but the average price looks like it's going to be close to 62 and 4 for most companies. And so, gas, I think was in the high $5 range, $5.80, $5.90 last year, so a lot of the 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 companies with resource plays like the Spraberry and the Eagle Ford, you're going to have a lot flexibility in regard to your booking practices, and we haven't decided yet how we are going to manage that over the next several years.

Great, thank you.

Next we'll hear from Robert Christianson with Buckingham Research Group.

Yes, is the geology of the Eagle Ford Shale something that causes you to take the go slow approach, wait and see, watch and see? Is there something more complicated here that -- I just can't believe that you're going to run only one rig. What is slowing you?

What is slowing us, Bob?

Yes.

I guess we're a little bit more conservative than our peers. I mean so far, the data points are very, very positive and we're stepping out. Our third well, I think it's shown on the map that we're stepping out a good back to the middle of the trend. We're putting some of our wells in the old window, we're putting some of our wells in the gas condensate window; we're putting some of our wells in the gas window. So we're looking at all aspects of our acreage. We just want to be more careful instead of jumping up to three to five rigs like some of our peers are doing with very little production there. So give us about six months and bringing in a potential JV partner, and I think you'll see us accelerating it significantly in about six months.

Because we all see these fabulous IPs, so you have reservations about how these wells will hold up and you would like to see how industry wells hold up before getting over a log on this thing? Is that --?

No, our well is performing expect like Petrohawk's wells on 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.

Fair. Thanks, Scott.

Okay.

Next we'll hear from Joe Allman with JPMorgan.

Thank you. Good morning, everybody.

Hi, Joe, how are you doing?

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

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

Okay, and -- thanks. Then in terms of just different topic, on the water flood in the Spraberry area, in that 7,000-acre area, what's the existing production? What's the current production? And then a good water flood you expected it to get up to what level?

I think the current production in the unit in question where the water flood's going to be done is today only about 800 barrels a day. So it's a relatively small area. It's 7000-plus acres, which is the water flood consideration area. What we've talked about through time that the empirical evidence would show that we would expect approximately 50% bump in the areas where we've implemented the water flood. It would come in some six to nine months after the water flood is implemented.

Okay, thanks. Then assuming a successful water flood there, what would be the next step for you guys?

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

Okay. Very helpful. Thank you.

Leo Mariani with RBC has our next question.

Yes, good morning here, guys.

Hey, Leo.

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

Yes, obviously, two of them are going to be with reprocess 3D, two appraisal wells on two of the bigger prospects that we are seeing 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're excited about all three of them. We should start sometime in late December, early January. Take about three, three and a half months.

Okay. And you're just going to have one operated rig out there and you think you'll have all the well results in three and a half months?

Once we start, three and a half months from the time we start in January, so we should have results by April, right before earnings in May for first quarter.

Okay, and I guess E&I is also drilling a couple of wells and those are going to be appraisal wells or are those more rank exploration?

They are drilling out two appraisal wells now as we speak. Fourth quarter and they will probably be drilling more appraisal wells going into 2010, but we haven't decided jointly on a budget yet for 2010 with E&I.

Okay. Jumping over to Alaska, just so I understood some of you all's commentary which you had in your press release, are you guys currently drilling, or are you taking a bit of a hiatus there with the rig?

We're not drilling as we speak. As I mentioned, we're completing our Nuiqsut drilling. We are doing some preparatory work for some completions in early 2010 and will be ramping up the drilling here in terms of the shallower [cut sea] drilling as soon as we have freeze. We need to have a frozen scenario before we can drill those wells, because they have a potential to flow the surface as is Alaskan rule. So we're waiting on the freeze-up, then we'll be back to drilling.

Okay. And just kind of curious as to how you think about your production out there. Looks like you've had a really nice ramp up into the second half of 2009. Where could we expect to be another 12 months, as we get into kind of the last half of 2010 with your volumes?

Yes, I think with our ramp up, we're going to be somewhere up closer to 10% from fourth quarter '09 to fourth quarter 2010 and then going to 2011 with our Spraberry -- aggressive Spraberry program in Alaska, without any Eagle Ford potential accelerating, we're targeting 10% double-digit production growth plus from 2011 on.

Okay. I guess I was particularly curious as to what you thought your Alaska volumes would do, kind of over that similar period, fourth quarter '09 to fourth quarter 2010.

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

Okay, thanks, guys.

Thanks, Leo.

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

Again, we appreciate everybody listening in on the call and taking the time. If you've got any further questions, please give us a call, Frank and his group. We look forward to seeing you all next quarter.

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