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Pioneer Natural Resources Co. (NYSE:PXD)

Q2 2009 Earnings Call

August 5, 2009 10:00 am ET

Executives

Frank Hopkins - VP of IR

Scott Sheffield - Chairman and CEO

Tim Dove - President and COO

Rich Dealy - EVP and CFO

Analysts

David Kistler - Simmons & Company

Michael Jacobs - Tudor, Pickering, Holt

John Freeman - Raymond James

Brian Singer - Goldman Sachs

Leo Mariani - RBC

Presentation David Tameron - Wells Fargo

Xin Liu - JPMorgan

Operator

Welcome to the Pioneer Natural Resources second quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer and Frank Hopkins, Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement the comments today. These slides can be accessed over the Internet at www.pxc.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors and then select Investor Presentations.

The company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to the 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 again this quarter. Let me briefly go through the agenda for today's call. Scott is going to be up first. He will summarize the financial and operating highlights for the first quarter. Again, another solid quarter for Pioneer. He is then going to focus on what the outlook is for the remainder of this year and he is going to provide some early thoughts on what to look forward to with respect to Pioneer in 2010.

After Scott concludes his remarks, Tim will go through the performance of our key assets in the second quarter and expectations for the remainder of this year and a little bit, again about the early part of next year.

Rich is then going to cover the financial highlights for the second quarter and he will go through the guidance for the third quarter coming up. After that, we will open up the call to your questions.

With that, I'll turn the call over to Scott.

Scott Sheffield

Thanks, Frank. Good morning. We will start out on highlights on slide number three. Second quarter 2009, adjusted income of $18 million, excludes our market-to-market losses of $110 million after-tax or $0.96 per share. Also, that includes a net gain from three unusual items totaling $31 million after-tax, which Rich will go over in more detail.

Second quarter production, 117,000 barrels a day. That excludes the fact that we had 2,000 barrels a day shut-in unplanned third-party pipeline repairs in Alaska and also in the West Panhandle field in Texas.

Excluding discontinued ops, we had 115,000 barrels a day. We will comment on that later, involves our shelf properties which we have an agreement to sell and expect to close third quarter.

Looking at the last 12 months, we were up 3% versus second quarter 2008. What is more important is the fact that LOE per BOE is down another 15% versus first quarter. We are basically down from the high of third and fourth quarter of 2008 about 30%. So, tremendous initiatives by entire operating staff and operating division in regard to achieving tremendous reductions in LOE.

Also, in addition, we very much believe in a free cash flow model, reduced debt by $97 million during the quarter. We do expect to generate somewhere between $100 million and $150 million of total debt reduction during 2009.

In addition to help get drilling started, we have added significant amount of derivatives with the recent run-up, again another run-up in oil and some in gas. Today, we are moving forward and protecting most of the cash flow in 2010-2011, using three-way instruments.

Combination of puts and collars allows us to lock in prices somewhere between $65 to $75 during those two years with upside somewhere between $84 about $95 during those two years. We are 80% covered in 2010 on oil and 65% on oil in 2011. Also, our gas is up to 80% covered. We do have a lot of three ways on gas also, that gives us upside to about $8 per MCF and some more in 30% in 2011.

What is also important is the continuing performance of our Alaska project. The first few wells we have brought on came from the Kuparuk zone, a fairly high prolific producing zone. We have been focused on the Nuiqsut zone, which is our main producing horizon. Fracture-stimulated two wells just recently. Combined IPs of 5,400 barrels a day. Tim will talk more about it, but Alaska will be over-performing obviously going into the second half of 2009 and going into 2010.

So again very successful and that's about two to three times what we had expected from an un-stimulated well. As I mentioned earlier, we did sign a PSA to exit the Gulf of Mexico shelf properties. That's for about $25 million and we do expect to close the third quarter.

Turning to slide number four; with the capital spending of about $300 million this year with our long RP, shallow decline than most companies have, we are still allowed essentially with a tremendous shutdown in rig activity to generate a 5% plus production per share growth in 2009 and versus 2008.

Turning to slide number five; capital spending in 2009, again it's front-end loaded at about $162 million for the first half of the year. We expect to totally spend about $300 million. Third quarter should be our lowest spend rate. Obviously, we will be talking about picking up activity significantly in the fourth quarter to reach that $300 million number. We do expect to generate about $100 million to $150 million of free cash flow. You can see most of the opportunities obviously are focused on oil in 2009 and we expect the same to happen in 2010.

Slide number six; for the tremendous economics, the significant reduction in well cost, tremendous returns we are seeing in Alaska, Tunisia and Spraberry, we will be going out for bid sometime in the next few weeks to start an aggressive drilling program, starting back up again with somewhere around 10 to 12 rigs in the Spraberry Trend area. We hope to have all rigs up and running by January 1t

Longer-term, we expect to double and triple the rig count going into the following two years, again aggressively ramping up Spraberry Trend area, continuing to put on, at least have two years of hedges using primarily three ways to allow upside and protect the downside to aggressively help protect the economics.

Alaska will continue as is. Tunisia will pick up some time late fourth quarter this year, begin a very aggressive drilling program focused on oil and then we are picking up a rig in the third quarter again to obviously drill a series of several wells going into 2010 to find out the type of potential that we could have in our Eagle Ford Shale. So the purpose of the program is really to test all of our acreage with several wells.

The CapEx is expected to be about $550 million to $700 million. The primary reason that we have a range, obviously initially 80% will be focused on oil, is the fact that we don't really have a good handle obviously, even though we are hedged, what gas prices are going to be. We have about four forecasts from outside sources including CERA, PIRA, Ventyx, Wood Mackenzie, and three of them are at $4 for NYMEX next year, one is at $6. So obviously there is all types of gas predictions in 2010.

If we continue to see low gas prices in 2010, obviously we will shift a lot of the $150 million, up to $700 million back into oil in the Spraberry. If gas is strong, much better, $6 plus, obviously a lot of that will go into gas drilling. In addition, we have $1 billion of operating cash flow based on our hedges. We have upside close to $1.2 billion if we hit the upside of our hedges on our three-ways. So obviously we have a lot of excess cash flow and a lot of it that can be put back into various areas.

So we are being cautious going into [2010] with this smaller budget that generates significant amount of free cash flow, expect quarterly production growth to start obviously with the first quarter in 2010.

Finally, in slide number seven, why invest in PXD? Obviously, we have probably the largest oil potential resource base of any company in the US, especially with the Spraberry trend area, Alaska and Tunisia, huge amount of drilling inventory. Obviously, the focus will be on those three assets. Spraberry, Tunisia, we will resume drilling there aggressively and continue to ramp it up especially in the Spraberry Trend area during 2010 through 2012. Very attractive derivative positions using three-ways with upside.

We are going to deliver free cash flow in 2009 and beyond, continuing to improve the balance sheet and our financial flexibility. It is important for us with our large acreage position of over 300,000 acres to find out the true potential of our Eagle Ford Shale resource potential and we should know that over the next six to nine months.

Obviously, margins are improving due to aggressive cost cutting initiatives that Tim and his staff have put in place throughout all of our operating divisions, and congratulations to those staff achieving way beyond what I expected within a six-month timeframe.

In addition, our low decline assets really require minimal maintenance capital and generate very stable cash flow and production, which allows us why we could have drilled through this cycle like a lot of our peers. Our debt would have been $500 million, $600 million, $700 million higher but it's important to invest the money wisely and that is what we have done and we will obviously be ramping up starting late fourth quarter going into 2010.

Let me turn it over to Tim.

Tim Dove

Thanks, Scott. In the interest of brevity, I will just be limiting my discussion to our three areas where we have current drilling activity, and then I will follow that up with a review of the quarterly production forecasts as we look ahead to the next three quarters.

The first of those slides is slide eight, a discussion surrounding the Spraberry foundation asset that really is underpinning Pioneer's growth from an oil perspective. The asset continues to perform extremely well. Our production is up versus first half of 2008 about 12%, and that's reflective of a strong drilling campaign in 2008.

We will be in fact after all these months of being not drilling in the non-drilling scenario, we will now be starting up one rig. In fact, we are supposed to spud our first well tomorrow in the Spraberry trend area. So, that's an important day for us to get back to the growth scenarios that have always played out so well in the Spraberry trend.

As Scott has already alluded to, we will have about 10 to 12 rigs running January 2010. The idea is to begin the process of contracting those rigs in August and September, have several rigs working by the end of the fourth quarter, so as to be hot and running efficiently with those 10 to 12 rigs in early January. The reason for that of course is with the hedges in place, with the strip prices being very encouraging, we are generating extremely strong returns from this drilling campaign.

For instance, for the wells that are drilled deep to the Wolfcamp, we are seeing returns of about 60% pre-tax plus. So that gives us a lot of encouragement that this drilling campaign can really add significant value and the other factor of course is, we have seen substantial reductions in well costs. Current estimates would say in the Permian Basin our well cost would come down over 30%. We will be able to give you more of a final number on that once we contract the rigs and get to the bottom line number here in the next couple of months.

Those rigs that will be generating the growth will be able to drill some 250 wells next year. Most of those wells will be drilled either deeper into the Wolfcamp and/or completions into the Spraberry shale/silt interval that we have been talking about over the last 12 months.

In addition, we have some exciting news regarding our plan to finally implement a full scale waterflood in the field. As you know, if you have been following Pioneer for a long time, we have been talking about the need to increase our recovery rate. There is a large initiative going on inside the company to do so. Considering the 30 billion barrels of oil in place in the field and the implementation of the waterflood is toward that end, it will be put in place in one of the Spraberry units. The current thinking is, it will be about a 7,000 acre flood. We will be drilling six new water injector wells. We will be converting five existing wells into injectors and be drilling a bunch of new wells to drill alongside current producers, and this we think will have excellent results and we are looking forward to those results.

The economics, of course, benefit from the fact that it reduces our water trucking costs in the sense that we are able to simply re-inject produce water and as another example of where the economics benefit. We will simply be reintroducing water into the Spraberry field at essentially zero PSI versus having pumped it under high pressure in other zones.

Empirical data says that this is from floods that have been put in place back since the '60s that we should see a response, and a rather dramatic response is expected in some six to nine months after we put this in place. So we are really excited to see how this waterflood plays out, because it's an important contribution to this idea of increasing recoveries.

Production is expected to grow year-to-year about 5%. Of course, we are on decline in this field, while we have not been drilling and we hope to stop that situation with the return of the drilling campaign 2010.

Slide nine is a discussion surrounding Alaska. As Scott has already mentioned, we had a great deal of success in our summer drilling campaign and we are just starting to see the effect on production.

Our first half production was about 4,000 barrels of oil a day. As we have already alluded to you in prior discussions, our second quarter production was curtailed about a 1,000 barrels of oil a day due to pipeline repairs at a major oil company, third-party water delivery system. We need the water of course for maintenance of pressure in the field, and so we were limited as to what we could produce.

We also were prorated on TAPS for a couple of days for equipment upgrades. So you can see this is third-party issues, but suffice to say now we have got most of those behind us. Sufficient water is now available for injection to increase volumes and we are doing just that.

In terms of the drilling campaign, we have now drilled five horizontal Nuiqsut laterals during the summer. Actually, we are drilling; we have got one left to go. We have got three producers and two injectors, and the results look very encouraging so far.

Our first injection well was produced unstimulated basis to set a baseline for what an unstimulated well could do and stabilized at a rate of about 1,000 barrels a day growth before we are now going to be converting it into a water injection well this month. It gave us a lot of confidence that unstimulated wells will in fact produce at good rates.

That said, our two first stimulated Nuiqsut producers suggest that we have many multiples of that that can be achieved by fracing the well, some two to three times the unstimulated rate and that's what gets to you a combined 5,400 barrels a day gross IP for those two wells and the thinking is, we will be able to produce these wells at flatter rates for longer periods of time with the fracs.

We are, as I said, starting to see the production impact. Current gross production in the field is about 10,000 barrels a day. Of course, we have 70% of that. Second half production is expected to average between 6,000 and 7,000 barrels of oil per day, as we look forward and they will be growing into 2010 as well.

If we still see substantial resource potential here, some 120 to 150 million barrels of oil, importantly only about 10 million barrels of that have been booked to-date, and as a result, Alaska I think contributes significantly to reserve replacement numbers for Pioneer into the future. So overall, Alaska continues to outperform our expectations.

Slide 10 a review of our South Texas drilling. Of course, we are not doing much drilling now other than for an Eagle Ford program, that Scott has alluded to. Our production was up in the first of this year compared to the first half of last year. That's because we had an excellent Edwards drilling campaign in 2008. Of course, we shut that down, due to the fact that gas prices were not cooperative during the time period. It goes to show you if we were drilling in the Edwards, we would have a substantial ability to ramp up production as we look forward.

A lot of that's coming from the fact we have completed the interpretation of our seismic across this wide swath of acreage and from all of the wells that we have drilled, some 150 plus wells. That has allowed us looking forward to identify about 200 optimized Edwards drilling locations for future drilling and those will be drilled of course when gas prices improve in order to meet our internal hurdle rates.

Importantly, as we drill through all those 150 wells, we drilled right through the Eagle Ford Shale sitting above the Edwards and we are just in the process of ramping up an Eagle Ford Shale a campaign as we speak.

Our first well that we reported on in the past incurred mechanical problems. We had a casing failure. We had a sidetrack. The combination of those altered the well trajectory, such that we only have a limited amount of the hole section in the bottom half of the Eagle Ford Shale, which is the more brittle and therefore more able to take a frac.

The result was out of eight planned frac stages, we have only got two we put away properly. We were encouraged with the fact that even with that mechanical issue that we have with this well, the fact that we have 3.7 million cubic feet a day equivalent was encouraging.

The program as we look forward right now will be a series of wells. The current thinking is we would drill a series of five wells back-to-back starting late August, testing various areas of this extensive acreage position we have, and all of those locations are currently picked. So we are ready to get after a substantial drilling campaign to prove up this resource base across Pioneer's extensive acreage.

Overall, the South Texas area is on decline as we are not drilling today, and of course that decline can be stemmed immediately upon putting the rigs back to work when gas prices cooperate.

Slide 11 now turning more to a review of the quarterly production, looking out several quarters. This slide has got a lot of material on it, but let me take you through it from left to right. First of all, our first quarter 2009 production as everyone think back towards this, we were affected by the hurricane last fall and the result of which was, we pushed a lot of NGL inventory into the first quarter. You can see as a result, the first quarter was overstated by that effect and of the 10,000 barrels a day decline that you saw from the first quarter to the second quarter, 4,000 barrels a day is related to that NGL effect.

The 10,000 barrel a day drop is really misleading and that's why we put this explanation in here as to why it fell as much as it did. About 2,000 barrels a day of that decline were related to what Scott had referred to and I did earlier on this pipeline repair business in Alaska for the water availability.

In addition, we had another issue, happened to be with the same major oil company, in terms of having issues on pipeline supports, on our condensate gathering pipeline in our West Panhandle field on pipelines that went over a river. The result of which we were shutdown for a month, in terms of our ability to get condensate sales up to their normal levels which lost another 1,000 barrels a day. So those were issues that we now have rectified.

Looking to the Natural field decline, it was about 4,000 barrels a day in the second quarter and that is related to the fact that this is the quarter you are going to see the major declines, owing to the fact you are going to get the flush production from your 2008 drilling campaign. Looking forward, third quarter production will be down slightly, again just natural declines.

We will be affected in the fourth quarter by the fact that for the whole month of October, it appears that South Africa will be turning around the gas to liquids plant, which takes our natural gas. So, it will be shutdown for a third of the fourth quarter. That's why you see the dip there.

Looking forward to the first quarter of 2010, we will have a 5,000 barrel a day increase, simply because of the expiration of the VPP obligation surrounding Hugoton. Of course, as our drilling resumes, we should see pick up in growth, obviously as we look at it currently will be Spraberry drilling, Tunisia, Alaska, oil related projects and we will be looking forward to getting back and as we get into 2010, into a quarterly growth model.

Quarterly growth is easy to do. It is just a matter of how much we are going to put the drill bit to work and how gas prices cooperate. I do have backup slides here regarding Raton, and Mid-Continent, Tunisia and South Africa. We aren't covering those. We don’t have much activity there. If you have any questions, please let us know and either in this call or later.

With that, I will pass it on to Rich for a review of the quarter's financials and his outlook for next quarter.

Rich Dealy

Thanks, Tim. Turning to slide 12, second quarter earnings summary. We did report a net loss of $92 million or $0.80 for the quarter. That did include, as Scott mentioned, a $110 million after-tax, mark-to-market, non-cash derivative losses, primarily due to the increase in the strip for oil and gas prices from March 31 to June 30.

Also included in the numbers were three other items. One, we got $55 million after-tax of cash in for Alaskan PPT credits. We also increased our accrual by $10 million for the abandonment of our East Cameron 322 platform that went down with hurricane Rita. Just as a side note, we have spent about $180 million on that project to abandon that project since it happened, and we still believe a substantial portion of that will be covered by insurance that we will get in future periods.

We also had $14 million after-tax effect from terminated stack rig charges or $0.13 related to that item. So when you combine all those items, our net loss for the quarter would have been $13 million or $0.10 per share.

Looking at the bottom of this slide, guidance versus results, we have added a column this time to reflect the activity including discontinued ops and then the last column on the right is the results on a GAAP basis, excluding discontinued ops. Scott and Tim both talked about production, so I think you are well informed on that. Production costs came in, the asset teams did an excellent job as Scott mentioned. I'll cover that in more detail on a later slide.

Exploration abandonments came in inside the range of $22 million. DD&A of $15.80 per BOE, slightly below the range primarily due to positive reserve revisions related to higher oil prices at the end of the quarter and G&A and interest were as expected. Non-controlling interest is really related to our minority interest in PSE shows a lot of one, but really if you adjust for PSE's mark-to-market adjustment, it was right inside the range of where we would have expected.

Rig stack expense came in at $23 million slightly above our range, primarily due to terminating another one rig that we hadn't planned on coming into the quarter. Cash taxes at $7 million, where we would have expected them and our effective tax rate of 32%, below where we forecasted but really just a combination of having foreign earnings and higher tax rate jurisdictions, primarily Tunisia offset by US losses which is primarily due to the mark-to-market charge in the US at a lower tax rate. When you combine those two, you get to the 32% effective tax rate.

Turning to slide 13, price realizations; you can see oil prices, we were up 34% versus the first quarter at $70.89 per barrel, NGLs were up 17% to $26.78 and gas prices as we all aware continued to be weak during the quarter and were down 21% relative to the first quarter.

At the bottom of the slide, we tried to outline in the first horizontal bar there, what our derivative impact is included in these price realizations and in the second line is the derivative impact since we discontinued hedge accounting February 1. That's not included in these realizations, but included in derivative losses on the income statement.

So that's there for your benefit. Be happy to answer any questions if you have any on that, when you look at it.

Turning to slide 14, production costs per BOE, $10.33 for the quarter. Outstanding job by the asset teams that represent a base LOE of 15% reduction from the first quarter, over 20% since the fourth quarter, outlined on the right side there is the number of items that have contributed to that.

Water disposal, water hauling, we have added salt water disposal wells in a number of places. We have reduced and renegotiated our hauling contracts as well as put some water hauling rigs internally to work in the Spraberry area. So, that’s helped. We have converted some leased and rented facilities into owned facilities. That reduced our cost on that front.

On the power side, Tim talked last time about renegotiating our electricity contracts. We have done that. We have optimized our compression, really adjusting the horsepower to be at the appropriate level, which have reduced some of our rental costs there and we have continued particularly in the Raton and Spraberry areas using internal services to control our costs as well. So as we look forward to the third quarter, I will give you some guide, but we still expect it to be in that $10 to $11 range as well.

Turning to slide 15, talking about capital. We still are focused on a $300 million budget for the year. That was front-end loaded at $108 million. In the second quarter, we are half of that at $54 million, really looking forward to the third quarter, expected to be about that same range with drilling going on in Alaska, putting the rig back to work in Spraberry, the Eagle Ford activity and some facility work in Tunisia.

As we look to the fourth quarter, as Tim talked about, we are ramping up our rig count in the Spraberry area and so that higher cost represents getting those rigs up and running late in the year. So, they're all operational January 1, 2010. So, we expect to be about $80 million in the fourth quarter.

Turning to slide 16, one of the things that give us confidence and putting those rigs back to work is the derivative positions we have added. Over the year, we added quite a few, we announced in our first quarter call. Since that time, we have added 12,000 barrels per day of three-way contracts for 2010 and 2011 with upside to $90 and $100 respectively.

We have also added 50 million cubic feet a day of gas for the first half of 2010. That's not listed here, $5.60 per MMBTU and 50 million a day of gas of three-ways in 2011 with upside up to $8.55.

As we talked last quarter, our real objective of adding this derivative was to get to a minimum level of cash flow that we could protect for 2010 to allow us to resume our drilling program, plus achieve meaningful debt reduction. So with 80% of our oil and gas for both 2010 hedged, we feel very confident that we will achieve that $1 billion operating cash flow next year and we have added to 2011 a 65% of our oil hedged, 30% of our gas and expect over the coming months, as we see price rises, add to those levels as well.

Turning to slide 17, third quarter guidance; production for the third quarter at 110,000 to 115,000 BOEs per day. This assumes no production from the shelf assets that we are assuming will be in discontinued ops and that sale closed in the third quarter.

Production costs, $10 to $11 consistent with where we ended up in second quarter. Exploration abandonment $15 million to $25 million, DD&A down slightly from the second quarter $15.50 to $16.50 on the back of a higher oil prices. G&A and interest expense similar to what we have been in the last couple quarters.

Rig stack charges are coming down relative to where we have been in the past couple of quarters, mainly because we have had a number of rigs come off contract in the second quarter and in to the third quarter and putting a couple rigs back to work in the third quarter.

The rest of items are very similar to what we had in the past. So there not any changes there. So with that, I would point you to the supplemental slides, that Tim talked about on slide 18, there for your review. So I encourage you to take a look at those. We would be happy to, now at this point, turn the call over and answer any questions.

Question-and-Answer Session

Operator

(Operator Instructions). From Simmons & Company, we will go to David Kistler.

David Kistler - Simmons & Company

Quick question with respect to contracting additional rigs or going forward with the process of adding additional rigs. Can you talk a little bit about the type of rigs you're looking for, the availability, and price expectations that we should be thinking of as we model?

Scott Sheffield

Yes, as Tim mentioned, the costs are down 30% pretty much across the board. We are going after bids in September and the type of rigs we need in the Spraberry are roughly about a 1,000 horsepower rigs. Sometimes we can get by with less. Obviously, there is plenty on the marketplace. So we think obviously over the next year or two with gas prices low that obviously is the best time to be drilling, oil drilling. So we won't get the exact prices until some time in September.

David Kistler - Simmons & Company

I think if I recall correctly, you had previously mentioned that you thought something sub-$10,000 is kind of the target?

Scott Sheffield

Yes, $10,000, in that range or less.

David Kistler - Simmons & Company

Okay.

Scott Sheffield

So we've heard of some much lower rates out in West Texas, but we won't have a handle until we can actually get the bids.

David Kistler - Simmons & Company

Then jumping to Alaska real quickly. With the third-party water issues, can you talk a little bit about what those issues were and what you've done to ensure that that's not a problem in the future?

Tim Dove

Well, first of all, the issues in question were related to corrosion in the water pipeline system of the major oil company in question. That led to a need to replace sections of the pipeline which shutdown water delivery. What we did in the interim was to take remedial steps to use sea water for injection, which was limited as to the amount of oil we could pump and the results of which is we were only able to produce a lesser amount of oil in order to keep that barrel for barrel equivalency.

Looking forward, today the remediation steps taken by the third party have now been completed. We have all the water we need. We are evaluating as you might expect based on this having occurred methods to make sure we are self-sufficient on water handling and water availability. So that is being undergone as well. I would anticipate looking forward, we will actually spend money to make sure we are self-sufficient on water looking forward.

David Kistler - Simmons & Company

Then just on the theme of water and the water injections that you mentioned then in the Spraberry. Can you talk a little bit about how you are designing that waterflood as far as, thinking about it more from the standpoint of the specific patterns that you are going to use, things like that, or is it too early to even get there?

Tim Dove

It's a little bit too early. I mean this is a different kind of water flood as I've mentioned to a lot of investors talking about this. We are not driving water through the system here as much as we are imbibing water into the system. So we slowly introduce water into the system so as to fill up all the fracture systems and then by adding more water from that point. We are actually imbibing water into the rock leading to increased oil production.

The patterns are really a combination of injectors and producers, intermingled throughout the whole 7,000 acres, but the current thinking is we would have some 100, 110 wells producing in the 7,000 acres. So you can see, we have a large number of injectors producing injecting water plus a large number of producing wells.

David Kistler - Simmons & Company

What are the kind of expected uptick and recoveries that you're back of the envelope targeting at this point?

Tim Dove

What I can do is speak to empirical evidence more than I can to what we're expecting. The empirical evidence shows that it's not unreasonable to expect a 50% uptick in production. As I mentioned also, it's anticipated that would not occur until some six to nine months after introduction of the water, but suffice to say a 50% increase in production is pretty substantial. That's the kind of number we are looking for, based on many empirical evidence. We'll see how we do in this area.

Operator

Next, we will hear from Michael Jacobs of Tudor, Pickering, Holt.

Michael Jacobs - Tudor, Pickering, Holt

I want to go back to the Spraberry. Given where costs are today and the hedges that you guided for 2010, what types of rates of return you expect to earn in both the Spraberry and the Wolfberry.

Scott Sheffield

It's going to range from 35% up to about 60%. So depending on if it's just a Spraberry doing well or all the way up to a Wolfberry well. So I'd say somewhere between $60 and $70 and $80, it's going to be up in the 50% to 80% range.

Michael Jacobs - Tudor, Pickering, Holt

Tim, I'm thinking back to our Spraberry class last year and specifically on the waterflood. Are you still assuming only 40% of your acreage can be developed ultimately on waterflood?

Tim Dove

I think the issues there are surrounding the land positions and making sure we have large continuous acreage. I think it's clear that not all acreage can be waterflooded. I think that's a reasonable number. I wouldn't peg it as a specific number. In other words, it might be 30 to 50, but that's why I'd use the range.

Michael Jacobs - Tudor, Pickering, Holt

When you think about six new wells, five injectors and associated facilities, can you give us a little bit of color on how much capital that's going to take and first guess at production response in both 2010 and 2011?

Tim Dove

I wish I could give you the last of those. I'm going to have to wait and see what the wells do, but the capital is actually relatively insignificant. If you look at what it costs to drill a new injector well, it's somewhere in the neighborhood of $800,000. The conversions are less than that. The total door-to-door cost of capital including the facilities for injection is probably going to run $6 million to $7 million only.

What we'll also be doing, we'll be supplementing the field with new producing wells, but of course we're going to be drilling producing wells anyway during our 2010 campaign. So if you just look at the waterflood itself, it's very insignificant in terms of total capital.

Michael Jacobs - Tudor, Pickering, Holt

When do you make the decision to undertake a similar project in the second unit?

Tim Dove

Well, I think the answer to that surrounds the last of your first questions which is let's see the response to this, let's see whether we do get that kind of 50% bump that we anticipate. If we do, it kind of opens up a whole new set of opportunities for us.

Michael Jacobs - Tudor, Pickering, Holt

One more, Tim. Now, that you've got 3D in hand, can you give us a little bit of color on what you're seeing and specifically talking about Tunisia and how do you think about your opportunity set for 2010 kind of reconciling that to your 2007 and 2008 results?

Tim Dove

Well, I defer to the explorations on the question of what we're seeing. The fact is that work is just being done. I think during the next two months, we will actually identify the prospects from the 3D, which will generate a drilling campaign. So I think it's a little bit early to answer that question.

Michael Jacobs - Tudor, Pickering, Holt

One last one and then I'll hop out. Scott, if we look at the midpoint of CapEx and assume roughly $600 million for 2010 capital, how do you think about increasing activity towards the upper end of the range versus addressing a balance sheet?

Scott Sheffield

A lot of it depends on natural gas prices and also the more we get to the upside of the number I mentioned, $1.2 billion, if oil continues to run up higher to the upper side of our three-ways, then obviously we'll have a lot more capital to invest in additional oil drilling, especially in the Spraberry Trend area.

Operator

Next, we will hear from Raymond James, John Freeman.

John Freeman - Raymond James

Looking at the Spraberry with the work you've all been doing in some of these non-traditional shaley, silty sections, obviously you've had some good results. I'm trying to get a sense of with the big ramp-up in an activity, when do you think you might have more definitive results on, it working in certain areas and not, others and maybe getting a reserve bump. Is this a late 2010 issue, 2011?

Scott Sheffield

Yes. We're seeing positive results from all of our efforts over the last two years, both 20-acre infield drilling, opening up the silty shale zones and also the Wolfberry work. So most of the wells that we're going to be drilling in 2010 and beyond will go into the Wolfcamp fairly deep. They will have additional fracs. We will open up the additional silt shale zones because we're seeing a nice uplift there somewhere in the 20% to 40% range. So it generally takes about 12 to 18 months to watch a typical decline curve and you'll see a turn on the [hydrobolic] decline curve to establish the right B factor. Then at that point in time, you'll be able to start moving up and increase your reserves at that point in time.

John Freeman - Raymond James

Looking at pipe inventory at the moment, given the ramp-up in activity, any idea when you might work off the inventory you've been holding since '08 and benefit from the other lower pricing environment on that side?

Scott Sheffield

On pipe inventory, we should benefit probably late at 2010 from that standpoint.

John Freeman - Raymond James

Then last question I have, I'll turn it over to somebody else. Tim, you mentioned, on the waterflood program how you're going to benefit on lowering the water disposal costs. Can you maybe elaborate a little bit more on that?

Tim Dove

As you know, every barrel of oil we produce in the Spraberry Trend area is coupled with four to five barrels of water. We've got lots of water we produce and that's a very costly proposition to dispose of that water. Not unreasonable for it to be $1 to $2 per barrel at times, (inaudible) fuel costs. So one of the economic benefits of the flood is to simply take the produced water re-injected into the same formation and the benefit you get from that of course is it's under very low pressure. So, you don't have a big cost of pumping. So it's actually a cost savings benefit, it helps push the economics even further to the positive.

Operator

Next, we will hear from Brian Singer, Goldman Sachs.

Brian Singer - Goldman Sachs

Following up on Spraberry, when you put together your expected rig counts, existing declines and results that you would expect from the Wolfberry waterflood, et cetera, what does a 10 to 12 rig count do from a production growth perspective I guess versus 40,000 BOE a day if you adjust day a second quarter for the VPPs?

Scott Sheffield

Adding back VPPs? If you go back from 2005, we were growing production on the Spraberry about 15% per year. We got up to about 17 rigs. So to me, if we can run 15 to 20 rigs, we can grow at 15% per year.

Our plan in 2008, we had hoped to get up to 30 rigs in ‘09 and 40 rigs in ‘10. So we're basically shifting everything back a year. So, '11 we hope to get up to 20 again and up to 30 in '12 and so on.

So we can continue to grow at 15% a year, 10 to 12. I don't have a number on top of my head. Frank will have to get back with you on that, 10 to 12 rigs. Our plan is not to stop at 10 to 12 rigs. So, obviously we'll be ramping up, doubling it within 12 months and continuing to increase it.

Brian Singer - Goldman Sachs

Then on the cost front, can you provide a little more color on the production costs, lease operating expense and the sustainability of the decreases and any variability you expect with commodity prices, if they rise over the next few quarters?

Rich Dealy

I'd say generally we've studied it and we believe the sustainability is okay. Obviously, if commodity prices go up, severance taxes will go up and so that will increase it and there will be probably some incremental work-over activity that goes on as well. So there probably it’s going to go down at the same rate, no? To the prior level out here and then to the extent we have higher commodity prices, they'll move back up a bit.

Brian Singer - Goldman Sachs

Was there one component more than others beyond the severance tax that drove down costs on a sustainable basis?

Rich Dealy

All those items I addressed really were reductions on a sustainable basis.

Operator

From RBC, Leo Mariani.

Leo Mariani - RBC

Question on Eagle Ford. Obviously you've got that well that you drilled a little while ago. Just curious if that well went right to production and kind of how that's holding up? I know it was on a pretty limited frac.

Scott Sheffield

Yes. Obviously, it's on [hydrobolic] decline curve. I have not kept up with the production on it. But as Tim mentioned, we did not get very little of the well bore was into the pay zone.

Leo Mariani - RBC

Jumping back to the Spraberry on the waterflood here, what kind of a well pattern do you guys envision out there in terms of what you're going to use for your pilot?

Rich Dealy

In general, it's going to be an inverted nine spot, but the point, as I said, it has more to do with this idea of, it's a different kind of flood. It's not a dry flood, per se. It's imbibitions flood. So you're really looking at a series of injection wells intermingled with producers. So it’s a little different than your normal flood.

Leo Mariani - RBC

Any sense of what the ratio of injectors to producers is, roughly?

Rich Dealy

You're probably going to have in the neighborhood of 10 to 20 injectors and probably a 120 producers, so it's going to be 10 to one, 11 to one. What I am talking about is, because you have some existing well bores.

Leo Mariani - RBC

How about incremental operating costs associated with that. Obviously, you're able to recycle the water. Do you see much of an uplifting cost, do you actually think you'll save money overall?

Rich Dealy

Part of the economics of this are related to cost savings from water handling. So actually we benefited, that’s part of the economic uplift of doing the waterflood is water hauling savings and for that matter just disposition water is a whole lot cheaper just to re-inject it into the existing field at low pressure.

Leo Mariani - RBC

Unrelated question. You guys had a $55 million benefit from the sale of the Alaskan tax credits in the first quarter. I guess that was an after-tax number. Is there a pre-tax number on that?

Rich Dealy

It’s the $87 million to $88 million that was straight from the state of Alaska.

Operator

Next, we will hear from (inaudible).

Unidentified Analyst

Couple of quick questions. First of all, just on the Spraberry, just given where oil is and the economics, any desire or chance to move up your rig activity plans to avoid rig stacking charges you otherwise might have in the second half?

Rich Dealy

It's all dependent on what gas prices do and the viability of oil prices, how high they get in 2010. So there is a good chance that Spraberry rig count could move up.

Unidentified Analyst

So they move up to January 1, is what you are saying?

Scott Sheffield

Between now and the end of the year, no. We're going to start all the rigs basically December 1 and have them all running January 1st.

Unidentified Analyst

Okay.

Scott Sheffield

Except the one rig that Tim mentioned in August.

Unidentified Analyst

So the rig stacking charges in third quarter is not related to the Spraberry area?

Scott Sheffield

Not really, no.

Unidentified Analyst

Okay. And then just a question on the waterflood. In terms of the oil in place, what kind of improvement in the recovery factor are you looking on the reserve side, not on the production side?

Tim Dove

If you look at some of our past information on this and you look at this on a section-by-section basis, the objective of the waterflood and some of the empirical evidence would say trying to get roughly about a 9% increase in recovery rates in that section. That's a substantial amount of oil though and that's one of the things we're trying to determine by affecting this waterflood.

Unidentified Analyst

So how much oil would be in place in the 7,000 acre waterflood?

Tim Dove

Each section has about 12.6 million BOE in place.

Unidentified Analyst

12.6 million, okay?

Tim Dove

That's an approximate number, needless to say.

Unidentified Analyst

Then just final question on the potential dropdown in the PSE, any color or comments on timing or size?

Scott Sheffield

It's in the process and we've already commented on size in our past PSE presentation, between 100 and 200 million.

Unidentified Analyst

Just in terms of your desire, are you willing to take more shares or are you looking more for a cash deal?

Scott Sheffield

We can't comment on this at this time.

Operator

From the Hartford Investment Management (inaudible).

Unidentified Analyst

Looking at Alaska, the wells, spot wells that you're drilling, can you talk to the well costs there and how much capital do you have allocated to that project this year?

Tim Dove

About $100 million total capital, 100 to $110 million is going to Alaska. Typical wells there, because you are dealing with long horizontal undulating wells that can range anywhere between 11 and 15 million, something like that.

Unidentified Analyst

What's the EUR assumption there?

Tim Dove

Well, you're talking about in the field itself overall or?

Unidentified Analyst

On that project. On the five wells that you're drilling in?

Tim Dove

We don't really look at it on an individual well basis. We've established pretty definitively that the Oooguruk field itself, just the existing development area that we're currently working on is in the neighborhood of 70 to 90 million barrels. Our resource potential is substantially higher than that due to other areas we can reach from the island and new ideas and prospectively we are working on today, but that gives you an idea of the size of the Oooguruk property development.

Unidentified Analyst

Then switching to the Eagle Ford, are you guys adding any additional acreage there?

Tim Dove

Yes.

Unidentified Analyst

You are. Okay. The well that you drilled, was that in LaSalle County?

Tim Dove

It was in DeWitt County.

Unidentified Analyst

DeWitt County. Okay, all right. It does very helpful. Then switching to talk about your hedging program, the three-way knock-outs that you layered in, what's the floor on that and then what's the knock-out price?

Scott Sheffield

We have a hedge schedule in back. There is no knock-out. I did not mention the word knock-out. We do not believe in knock-outs. These are three-way, combination of a short put, a long put and a call and it's on slide number 24 in the back of the exhibit. The average for 2010, the short put is about $53, the long put is about $66, and the call price is 84. So, between $53 and $66, we get $66, below $53 you add $13 plus and then we get an upside up to about $84 and then 2011, it's $58, $73 and $95.

Unidentified Analyst

Well, the short put at 53, then basically you owned oil under $53; right?

Scott Sheffield

Yes, it’s between $53 and $60. So we're giving up a call. So that allows us, oil could drop $13. We're still going to get $66.

Unidentified Analyst

Yes. You still protected, but under $53 you're naked.

Scott Sheffield

Now, you get $13 plus.

Rich Dealy

$13 or whatever the market is below that number.

Scott Sheffield

So, it drops to $43, you get $43 plus $13 and $56.

Unidentified Analyst

Okay. That's helpful.

Scott Sheffield

We just don't have the knock-out feature, which would cause you to skew both the upside and the downside of that. The knock-out feature allows if you fall below allows the whole thing to disappear. We do not have any knock-out features.

Operator

We will move on to David Tameron with Wells Fargo.

David Tameron - Wells Fargo

Could you guys talk about your costs, I think Tim you mentioned going forward Wolfcamp and you mentioned your costs came down and maybe mentioned a number. Can you give me what a well cost is running right now in the Spraberry?

Tim Dove

The deepest to the wells that is, as you mentioned those going to the Wolfcampm, at the peak were about $1.4 million. In fact, we had some over $1.4 million. Now, we would look at those as right at $1 million or somewhat less. I want to say depending upon the exact depth about $1 million, may be slightly less than that is current estimate where they would land.

David Tameron - Wells Fargo

Then on shallower wells.

Rich Dealy

Shallower wells, if anyone else sure you’re talking about could be down to $800,000.

Scott Sheffield

The shallowest to the wells is the best way to say it.

Tim Dove

You're going to have a range. You're going to have this range $800,000 to $1 million, depending on what well you're drilling.

David Tameron - Wells Fargo

That's good. Either you or Scott, can you talk about, it seemed like last quarter, Scott you fielded a number of questions on the conference call, asking what price would it take to get you to commit more rigs and you seemed too hesitant to at that point. Can you just talk about the change in your thinking between now and then or what you're seeing differently that you can ramp Spraberry now?

Scott Sheffield

We could have drilled a lot more Spraberry wells this year. I mean I'm surprised the market has rebounded. Just in March we had $35 crude and just a week ago, it dropped to $59. So the oil market is very, very sensitive based on world economic data we see. The dollar is getting weaker with it back to September lows. It's helped significantly.

Inventories are still very high, pretty much all products across the rest of the US and the world. So there is a lot of fundamentals point toward lower oil price. So, obviously with the hedges we pretty much, almost any scenario that I can see are or they another fall in commodities, we've locked in at least a minimum of $800 million cash flow, upside about $1.2 billion. So, that's why we feel very confident.

The returns are excellent at $60 oil. The returns are even very good at $50 oil. It's a question of non-boring sit there just continue oil drilling this year. If we were to continue our oil drilling, we would have bored heavily this year because of obviously the low gas prices. So, it's a combination of the returns, the well costs, operating costs coming down, economics and also having pretty much protecting cash flow next year.

David Tameron - Wells Fargo

Okay.

Scott Sheffield

It adds to aggressively starts Spraberry drilling.

David Tameron - Wells Fargo

It sounds just another three months of a little more certainty of what you're looking at, kind of got you off the sideline, is that fair.

Rich Dealy

Also, we wanted free cash flow for 2009 too. We could have borrowed $400 million, $500 million like other people did and had a little growth, but we felt it was more important to have free cash flow in '09 and also free cash flow in 2010.

David Tameron - Wells Fargo

Thank you and then one more question. If I look at LOE is down 15% quarter-over-quarter and I think Brian asked this question a little bit, but you have five bullet points in the slide on slide 14, where you go through the LOE cost reductions. Can you talk about LOE specifically, which components, can you swag that for me of the 15% is one or two dominating that piece?

Rich Dealy

I think each is contributing and of course it slightly different amounts.

David Tameron - Wells Fargo

Yeah.

Rich Dealy

A lot of these things are in place such as our electricity contract work that we mentioned earlier, last quarter. That contract is in place that. That will be dependent on what happens with natural gas prices. They're tied pretty closely to electricity prices. Accordingly, we have stronger natural gas prices, which we all hope for. With number one, we have an increase in our electricity costs, we'd also be back to drilling.

The others I think to a great extent are changes we've made that are in place and will continue to benefit from. That is to say, revamping our water hauling business so that we're doing a lot of it ourselves, revamping our water hauling contracts, drilling water injection wells. Once they're there, that money is spent, you're going to have that cost benefit continue.

On facilities, the same thing, infrastructure. Power and fuel as I mentioned is dependent upon number one what happens to natural gas price but also diesel. So it does depend somewhat on what's going to happen with the fuel costs.

Compression optimization is similar to facility. That is, take steps to optimize on the one hand and then as Rich had alluded to convert relatively expensive leasehold in the form of compression to ownership. That's a one-time savings that continues as well. Using our own crews is something we've done for quite a long time in the Raton basin and we're now doing it even more in Permian.

I see that as something that's a continuing trend for Pioneer to continue to keep a (inaudible) on costs, so you will see us do more and more of that as well. So it isn't to say we aren't subject to some creek, but what I am telling you is a lot of these things are specific steps that are kind of in concrete looking forward.

David Tameron - Wells Fargo

One final question and Scott you gave your view on the oil market. Natural gas rig count in the US a year from now, if I throw out the number 900, 950, do you say over or under that number?

Scott Sheffield

The strip right now is about $6. So like I said, there's three world forecasters that say it's going to be 4 next year, there's one at 6. So to me, what nobody has a handle on is what the Marcellus, Haynesville, the Woodford, Eagle Ford, all these shale plays, how many rigs does it take to keep production flat. Obviously, we don't have a handle on the economic recovery in this country. So I'd say the chances of having $6 for the year is probably going to be slim in my opinion next year.

Operator

Next we will hear from Xin Liu from JPMorgan.

Xin Liu - JPMorgan

In Alaska, now you have a couple well results. Can you provide more color on how much reserves you expect to book this year?

Tim Dove

We'll be booking some reserves, needless to say. As I mentioned earlier, we have not booked very many yet. We'll be just implementing the waterflood and we probably need more time to be able to justify the bookings substantially of most of the waterflood reserves, probably until 2010.

Xin Liu - JPMorgan

You mentioned you bought some Eagle Ford acreage. Can you talk about how much you paid for it on a per acre basis and how many acres?

Tim Dove

Due to competitive reasons, we're not at liberty to discuss that.

Xin Liu - JPMorgan

On the LOE front, you mentioned that you brought some of the services in-house. Any associated capital related to that?

Tim Dove

Obviously, there's some capital related to buying equipment, but it's relatively immaterial and it's fast payout.

Scott Sheffield

And its $0.50 on the dollar.

Tim Dove

It's cheap. That's right.

Operator

Our next question will come from [Eric Homer] with Wells Fargo Securities.

Unidentified Analyst

If I could just press on David's question a little bit on the Spraberry returns. Can you give a sense as to at the strip, kind of what the return looks like on Spraberry?

Scott Sheffield

At the strip it's much higher than I even gave out. A strip gets up to $95 by 2017. So you're probably in the 50% to 100% type returns.

Unidentified Analyst

Can you drill down on what F&D is that you're looking at as you did budgets and put the rigs to work?

Scott Sheffield

Tim gave out well costs and we're still in the average reserve in the 100,000 to 110,000 barrels per well. So, you can calculate it with the well costs that Tim gave out. So, it's still going to be in the $9 to $12 range, depending on where you drill in the Spraberry Trend area.

Operator

Gentlemen, there are no further questions at this time. I'll turn the conference back over to you.

Scott Sheffield

Okay. Again we appreciate all the questions this time. If you got further questions, please call Frank Hopkins and our Investor Relations staff. Look forward to seeing everybody out on the road. We'll look forward to the third quarter. Everybody have a good summer.

Operator

That does conclude today's conference. We thank you for your participation. You may now disconnect.

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Source: Pioneer Natural Resources Co. Q2 2009 Earnings Call Transcript
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