先鋒自然資源 (PXD) 2009 Q1 法說會逐字稿

Welcome to Pioneer Natural Resources first quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Chris Cheatwood, Executive Vice President, Geoscience; 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.PXB.com. Again, the internet site to access the slides related to today's call is www.PXB.com. At the website, select Investors, then select Investor Presentations.

The company's comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on Page 2 of the slide presentation and in the most recent public filings on Forms 10-Q or 10-K made with the Securities and Exchange Commission. As a reminder, this call is being recorded.

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

Good day, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Scott's going to kick things off. He'll review the financial and operating highlights for the first quarter, which saw Pioneer deliver strong production and great expense performance. He'll then comment on the company's outlook for the remainder of 2009. After Scott concludes his remarks, Tim's going to give a brief overview of the performance on our key assets in the first quarter and some things you should look out for as we go through the rest of the year. Also today, there's been a lot of interest in the market recently about the Eagle Ford Shale. So I've asked Chris Cheatwood to come and provide a brief update on our activities there as well as talk to you a little bit about the geology in the area. Rich will then cover the financial highlights for the first quarter, give you our forecast of what earnings guidance should be for the second quarter. After that, we'll open up the call for questions. So with that, I'll turn the call over to Scott.

Thanks, Frank. Good morning. We appreciate everyone taking time to listen to the call. On our highlights on slide number 3, we reported first quarter net loss of about $15 million, or about $0.13 per share. We had an after-tax noncash mark to market gain of about $47 million through hedging and after-tax unusual net charges totaling about $45 million. As Frank said, production continued to grow substantially, even though our rig count was going from about 30 rigs to one rig as we're drilling now.

When you look at first quarter 2008, production was up 15%. Again, the same key drivers we've had, Spraberry, South Texas Edwards play, our Alaska Oooguruk project, South Africa, and then Tunisia. We did go ahead and amend our unsecured senior credit facility. We have been well within all covenants. We did it obviously to further strengthen our financial flexibility, which Rich Dealy will talk more about. We're also beginning to initiate oil derivatives in 2010 and 2011. The strip got up to about $65 to $70 about several weeks ago. In fact, it's back up there a little bit better than that this week.

We have hedged about 25% to 30% of our forecasted production. Our strategy here is basically to try to lock in something close to the existing swap price of $65 to $70 in those two years, but give us some upside in each of those two years at $80 to $90 a barrel. So using three ways. Also, we continued to hedge more -- as we see spikes, our gas production in 2010 with that upside up to $7.50 to $8 in 2010. We now have 70% of our production in 2010 of gas hedged with a swap price roughly about $6 and with upside between $7.50 and $8.

We're continuing to see with our results of the last several quarters very encouraging results from our Spraberry shale interval testing. We've had some areas which Tim will talk more about that are exhibiting up to a 40% increase in production.

Chris will talk a lot more detail about the Eagle Ford Shale. Obviously we're in the process of fracing on this week, next week, our first Eagle Ford Shale well in South Texas. Also we'll be starting a second well, horizontal well in the third quarter. I think what's most important is the fact that I want to -- with well costs down over 25%, we expect another 10% to 15% increase. We expect to be 35% to 40% down by this summer. You couple that obviously with what's happening on the, on crude oil prices, we anticipate obviously starting up drilling aggressively in both Spraberry and also in Tunisia, continue with our Alaska program in 2010.

Probably what's most important with our announcements is the fact that we want to attribute to Tim -- [Kay Steel, Danny Kellem], all the asset VPs for achieving already the first quarter a large part of their target for the year. Our LOE is down 10% from fourth quarter 2008 if you look at it on the base. What's more important is the fact that base excluding taxes is down about 10%.

Turning to slide number 4, in regard to just showing the fact that with our strategy over the last three years, very consistent production growth. Obviously we way outperformed first quarter of 2009. About 2,500 barrels of that is attributable to NGLs. If you look at footnote number 3, makeup from the fourth quarter of 2008, but still even if you back those out, we way overperformed first quarter 2009. It shows the quality of our assets in regard when you move the rig count from 30 rigs down to one, same time.

Slide number 5, on a per share base, continued to -- we had obviously a tremendous share last year of 20% per share. In addition, this year will be a 5% plus. Again, the quality of our assets, all it takes is about $200 million in 2009, or even in 2010 to keep production flat within Pioneer. Slide number 6, in regard to capital spending, it's important to continue to have a free cash flow model. That's why our CapEx budget between $250 million and $300 million. We were front end loaded as we continue to reduce rigs in the first quarter. Obviously with one rig running now, the capital will come down substantially as you can look in the back in regard to forecasting capital spending. You can see most of it's oil related, 80%, and 20% gas.

Final slide before I turn it over to Tim, slide number 7, why invest in PXD -- obviously we have probably some of the greatest assets, very low decline, very stable cash flow. Obviously they are performing way above expectations. Obviously very attractive in a low commodity price environment. We don't have to fight the decline curve like a lot of peers.

Our inventory was primarily driven by oil, with the resource potential also greater than 60%. Continuing to have strong and improving financial flexibility. We are targeting free cash flow in 2009 and beyond. Obviously continue to take prudent decisive steps to reduce costs and improve returns, and with our hedging, we anticipate starting up a substantial rig count obviously in the first quarter of 2010, primarily in the Spraberry field and also in Tunisia. We'll continue to add derivatives in 2010 to 2011 as we've already hedged 25% to 30%.

Again, really if you look at it, it's really been a great quarter, both from production and cost reduction. We'll continue that. Let me turn it over to Tim to talk about our specific assets.

Thanks, Scott, and following up on that, as you all know, we're not doing a whole lot of drilling in 2009. That means our people are heavily focused on what we call around here operational excellence. And I think the results you have seen that Scott has alluded to both in terms of production and cost savings have shown just that. And our asset teams have done a tremendous job. Specifically the Spraberry Trend area, South Texas, [Midtown] -- all these US assets have had a very good first quarter and have contributed to the overall company's successful performance on production.

Spraberry's covered more in detail on Slide 8. Our production in the first quarter was up about 23% compared to the first quarter last year. This is as a result of having had a very successful 2008 drilling program. The date is now in on a comparison basis on some 300 wells, between 2008 and 2007 drilling, and what we can say now is 2008's campaign was one of the most successful over the last decade. In that comparison of wells, we increased production on a relative basis about 16% over 11 months of data compared to the same number of wells roughly in 2007. So it's one of the reasons why the Permian Basin production has been exceeding plan. In addition, of course, a large percentage of wells in 2008 were completed in the Wolfcamp, which has been a contributor to both reserves and production.

And we continue to see positive results from our nontraditional zones. 2008 and now into 2009 are years where we are continuing to make strides in understanding the potential contributions from the shaley, silty sections that had traditionally not been completed in the Spraberry Trend area. The work we've been doing of course is looking at well pairs, looking at wells where we are actually completing in the nontraditional sections versus offset wells where we were not and trying to get an understanding regarding the impact of the new completions. We're doing a lot of detailed science work, petrophysical modeling to understand these nontraditional pay intervals and also assessing what is the right number of fracs and frac packages to make sure we can optimize the results.

What we can say today after several quarters worth of work is that in certain areas of the field, we've seen significant increases in production, some areas 40% or higher than the offset control wells. And that's based on, in most cases, adding additional fracs in the nontraditional zones. And so we might not expect to see that across the entire field, but where we're seeing it, it's giving us enough intrigue to continue our study of this data looking ahead. I think you'll see us continue to increase the number of completions in nontraditional zones. So in conclusion, what we can say is the nontraditional zone work we've been doing has been promising in specific areas and what this likely means is we'll be requiring additional frac stages in a lot of these wells.

We did drill 17 wells in the first quarter as we finalized our program and laid the rest of the rigs down. We fraced a total of 41 wells, most of those having been done by our Raton frac fleet having come down from Colorado and we put those 41 wells on production.

Today, as I mentioned, we have no rigs running. We have about 900,000 acres that are held by production or that we have extended with cash for the lease hold. We found that cash is simply cheaper as a method to extend lease hold and drilling, at least until we see the costs come down even further.

That said, just because of the strong start we've gotten in 2009, we do expect production in the Spraberry Trend to grow about 5%. Again, we're the beneficiary of very low decline rate assets that need low amount of reinvestment, especially during these troubled times with low commodity prices. As Scott has already alluded to, we are getting the a lot more confidence that we'll be recommencing drilling here, probably early 2010, maybe slightly before as we get rigs warmed up to start the year in 2010 at a pace which is as yet undefined, but will be substantially higher obviously than we've done in 2009. And that's coming as the result of prices and hedges contributing to the economics of these wells in addition to cost reductions. We've already been able to implement and we think will be further reductions as well.

Turning to Page 9, I'm going to pass the baton over to Chris. As Scott has already mentioned, the Eagle Ford Shale has generated lot of attention and we thought it would be a good idea to have him discuss all of our South Texas operations with the focus also on the Eagle Ford.

Thanks, Tim. As Tim said, I'll spend most of my time talking about the Eagle Ford this morning. But I think it's important that we not overlook what we've accomplished in the Edwards Reef Trend that directly underlies (inaudible). Also it provides us a little historical perspective of the database that we have in the Eagle Ford.

From 1997 through 2005, we drilled around 80 horizontal wells in our Pawnee field that produces from the Edwards. We more than doubled the reserves in the field during that time and grew production from under 10 million cubic feet a day to over 50 million cubic feet a day. Because of our results and what we learned at Pawnee, we began picking up trend acreage in mid-2005 along the Edwards Reef play and acquired over 300,000 acres we still hold today. In 2006 through 2008, we shot over 900 square miles of 3D seismic, drilled around 75 wells, mostly horizontals, and grew production in the Edwards outside of Pawnee during this time from the previously mentioned 50 million cubic feet a day to over 120 million cubic feet a day. These are gross numbers that I'm quoting. As shown on the slide, that resulted in Q1 2008 to Q1 2009 production growth of 28%. Also, because of this drilling campaign, we currently have an inventory of over 200 Edwards locations to drill.

As we were drilling the wells in the Edwards play, we regularly had to flare gas as we drilled through the Austin Chalk and the Eagle Ford formations. We became very interested in these shallower formations and gathered information on them as we drilled our Edwards wells. Combining data from the logs and coring in these wells with our extensive 3D seismic has given us a very good picture of their potential over our acreage.

In late 2008, we drilled our first well to test the Eagle Ford formation in DeWitt County. We cored 180 feet of lower Eagle Ford in the vertical well and then drilled a 3,000 foot lateral. Completion of the lateral was deferred, so we can incorporate the rock property data from the core. The completion should be done in the next couple of weeks. We will be doing an eight-stage frac over that 3,000 foot lateral.

We're planning to drill a second horizontal well to test the Eagle Ford on our acreage in the third quarter. This well will be approximately 75 miles south of the first one. The distance between these wells, I think, gives you an idea of the scale [of] display across our acreage position. We had plans for a larger drilling campaign, but the world has changed significantly in the last year, and accordingly, as you've heard us discuss before, we've reduced our capital expenditures across the company. Because of this, production from our South Texas asset is expected to decline in 2009 about 5% relative to 2008.

Turning to Slide 10, I'll now talk about some Eagle Ford plays specifically. The Eagle Ford is a calcareous organic-rich shale that overlies our Edwards Reef play over our entire 300,000 plus acreage position as shown on the map. It ranges in depth from around 10,000 feet in the southwest to around 14,000 feet in the northeast. The thickness ranges from 120 feet thick to 250 feet thick. A good average thickness to use in calculating volumetrics is around 200 feet. The effective porosity averages consistently across the area around 10%. The formation is slightly overpressured, with a pressure gradient of 0.65 to 0.7 PSI input.

One of the most intriguing features across our acreage is the fracturing of the shallower Eagle Ford and Austin Chalk formation. Because we essentially have total 3D seismic coverage in our area, we can clearly see fracturing in these formations, both on the raw seismic data and especially from coherency processes. Most of our previously drilled Edwards wells had strong [mud log] shows, which frequently [would] flare gas while drilling throughout the lower Austin Chalk and Eagle Ford formations. This extends our gas column in many instances throughout the Edwards, Eagle Ford and lower Austin Chalk.

The magnitude of the natural fracturing on individual well production and recoveries is difficult to predict until we get multiple tests. But it is well known in these types of plays, that Mother Nature's contribution can be far greater than manmade horsepower. This could be a great benefit to us, both from well performance and reducing completion costs. As stated earlier, we have drilled around 150 horizontal wells in this area since 1997. Because of this, we feel comfortable that drilling and completion costs in the long run will average around $6 million. Wells during the initial phase have planned additional cost for [science] and we'll probably overdesign the completions on the first few wells, but I'm confident in our cost estimates long-term.

Most of the questions we have fielded today, as Frank alluded earlier, concerns how the Eagle Ford on our acreage compares to the new discoveries by Petrohawk in LaSalle County. You can see the location of their acreage position on the map relative to ours. Their play is slightly different in that it is concentrated [baseward] of the Edwards Reef Trend. They have completed four wells to date and are drilling two more at this time.

On the next slide, I'm going to show you well log and core data from their wells and ours. My comments will be brief and you can draw your own conclusions, because I think the data speaks for itself. The cross section on Slide 11 shows Petrohawk's Dora Martin well in LaSalle county on the left. This well is a strong producer in the Eagle Ford and next to it are two wells on our acreage. The well named Pioneer 1 on the right is a vertical log on the well where we drilled our 3,000 foot lateral and that well is currently complete. It's important to note that this well is located over 125 miles northeast of the Dora Martin. The well Pioneer 2 in the center is a vertical log near the location where we will drill our second well later this year. It is located over 50 miles from the Dora Martin log.

On all three logs, the curve on the left is the [gamma ray]. The center curve is [the prospectivity] and the right curve is density porosity, with density porosity greater than 9% highlighted in pink. I'm not showing the mud logs because I don't have one on the Dora Martin, but there were very strong gas shows throughout the Eagle Ford in both of our wells and I'm sure on theirs as well. Also shown is the location of the core taken in our first well. On the right is a table comparing published data by Petrohawk combined with log calculated and core data that compares the three wells and areas. I think the well from both the log and the new tables show all three to be very similar. So I hope this gives you a relative comparison to one you've been looking. Our next step, of course, is to confirm this with a couple of well test.

So to conclude today, I would say our South Texas acreage is fulfilling our expectation in the Edwards Reef play and the Eagle Ford Shale looks very promising. All of our data supports what you've heard from others so far about the new play. Also, it indicates our wells should perform similar to the current producers in LaSalle County. I look forward to discussing this again with you in the future when we have some well test results and some higher gas prices. I'll turn it back now to Tim to talk about Alaska.

Thank you very much. Appreciate that, Chris. Heading north to Alaska, in Oooguruk, our first quarter production was about 4,000 barrels a day net. That is essentially on plan. We were somewhat limited in terms of hitting the higher rate than planned due to water injection. We need to in this field inject a barrel of water for every barrel of oil that's produced. And we were limited due to constraints from the third party water delivery supplier due to some issues on their system that did not then allow us to have enough water to inject at a rate which would allow us to increase production to a higher level.

That said, as I mentioned, we did meet our production target. We're going to have to limit production on our high rate Kuparuk wells until we have sufficient water to inject, which is expected to be probably in the late part of the second quarter. Our capability to produce is probably more in the neighborhood of 10,000 to 12,000 barrels a day gross and we're now producing, as you know, about 6,000 on a gross basis, such that we have a lot more capability once we get the water injection in place.

We do plan, and are on target to drill and frac two of the new production wells during this summer. The frac equipment is on the island ready to go. Of course,the Nuiqsut is the larger of the two reservoirs in the overall Oooguruk development. We'll be very interested to see those results. Overall, the project is on schedule to produce about 5,000 barrels a day this year and gradually increase that to 10,000 to 14,000 barrels a day on a net basis as we continue the drilling campaign over the next several years. We will look at the opportunity to increase production in our production profile once we have some of these high rate Kuparuk wells on production after having determined that the water injection capabilities are at the right level. Again, we continue to see increased resource potential, and this has been covered in prior discussions, but nonetheless, we think Alaska has a lot of upside and long-term potential for Pioneer.

Slide 13, we don't cover our Mid-Continent assets very regularly, but I thought it made sense to do it in this call because if you ever had the right assets for a low gas price environment, the Mid-Continent assets of Pioneer are just that. It's the Hugoton and West Panhandle fields. These are stellar assets with a very low decline rate, low reinvestment requirements, and our asset teams there have done an excellent job in terms of attention to detail to maintain production at a very low decline rate. In addition, these will be actually growth assets for us as our VPP obligations in the Hugoton field will be expiring between now and the end of 2009. So these fields will grow for us looking ahead.

Slide 14, Raton, this is another very key low decline rate asset. It's performed exceptionally well and it's one of the reasons the company's overall production has done well. You see flat production in the first quarter, essentially the same as that in the first quarter of 2008, whereas 2008 actually had benefited from an acquisition done then, so it gives you an idea the production is doing very well. And we're not doing any drilling right now. We don't do any drilling until the conditions for pricing improve. But that said, we are employing the assets in this area in other areas of our field operations. I mentioned earlier the fact that we moved the frac fleet to Permian to frac wells there and we'll continue to look at these kind of synergies in our integrated model.

We are doing a lot of science work on the Pierre Shale. Of course, we did a lot of drilling in the Pierre Shale a couple years ago. Since we're not drilling this year, we're taking the opportunity to build extensive modeling, identifying sweet spots. One of the keys we've identified there is the ability to identify the fracture network that can lead to increased production in EURs from the Pierre Shale. Overall on this asset, we should see a slight decline in 2009 just as a result of not doing any drilling as compared to 2008.

On Slide 15, our Africa operations are covered succinctly. Tunisia on the top and South Africa on the bottom. Tunisia of course grew dramatically last year and into the first quarter of 2009, really the result of finalizing all of our oil processing and tankage investments at the end of 2008. We have curtailed drilling. We shot a substantial amount of 3D seismic during 2008 and are right now in the process of evaluating that, processing it. And the objective would be to return to drilling either later this year or into 2010 once the prospectivity from that 3D has been identified. Production should grow year to year about 5%.

South Africa, of course, we're just producing the South Coast gas project. At this time last year, we had Sable oil on production, but as a result of having put the gas project on production, we grew production substantially on a year-to-year basis. Overall production for this year from the South Coast gas project is expected to be about 30 million to 35 million cubic feet a day on a net basis. Importantly, having now disposed of our FPSO that was necessary in the production of oil, we now have reduced our operating costs down to less than $5 per BOE from some $30 at a time when we were producing oil. So our margins are very strong as a result in South Africa.

Turning to Slide 16, just a couple of comments regarding well costs -- as Scott has already alluded to the fact that we think our well costs really on an overall average basis across the company would have been reduced about 25% since the peak. We're targeting an additional 5% to 10%. I think that will be achievable when we put all the pieces together for a plan for the resumption of oil drilling. It was already mentioned we'll be embarking upon later this year with the idea of having rigs working in January 2010.

Finally, on cost reduction issues that are really more focused on production costs as covered on slide 17, our asset teams have done a phenomenal job of reducing costs. And in fact, I can point to some 120 initiatives in the company focused on LOE savings. And to date, those teams have identified about $40 million on an annual run rate basis of LOE savings this year compared to 2008. And you can already see that showing up in the results. Scott mentioned this, but you can see it very clearly in the financial results Rich will comment on here in a moment. Our LOE down about 10% compared to last quarter. So tremendous opportunities for cost savings have already been identified. We have 44 significant projects in six primary expense categories shown on Slide 17. I'll just cover a couple of things to give you some flavor for the types of things we're doing.

In water disposal, water hauling is a very expensive part of our business. We're taking the opportunity this year to improve our efficiencies in that regard, including drilling new water disposal wells in the Raton area. We're now utilizing our own trucks for water hauling in the Permian Basin as opposed to using those of third parties. And we're reducing rates on water hauling in the Barnett Shale area through new negotiations.

As power and fuel goes, we have new electricity rates that have put into effect as of January 1 in the Permian Basin, and also in the West Panhandle area of Texas that have substantially reduced our costs of energy. That's going to be a substantial savings going forward.

We're doing a lot this year during the idle time in terms of drilling, in terms of optimizing our compression. In a lot of cases what we're doing is replacing rental compression with Pioneer's own compression to increase efficiency, reduce downtime in some of the areas where compression is critical, particularly Raton and Barnett. And as another example, we continue to push the idea of integrated services even into our Permian operations, where today we have a 15-rig workover fleet pulling units that have in effect eliminated some third party activities in the field where we always have many rigs working just in terms of subsurface repairs.

So suffice it to say, this is a year where we have heavy attention to detail on all these operational matters. We have a philosophy to turn over every rock in terms of cost reduction, and I think you're starting to see the benefits of that philosophy. With that, I'll pass it over to Rich for a commentary regarding the financials for the quarter.

Thanks, Tim. As Scott mentioned, we had a net loss for the quarter of $15 million or $0.13 per share. That did include a number of unusual items that are detailed on Page 18. Going through the most significant ones, as Scott mentioned, we had $75 million mark-to-market gain in the quarter. That was primarily the gas prices falling in the quarter, so our derivative position became higher valued. That was $0.41 of income. We also had $7 million of Alaska PPT credits come in for $0.04.

Offsetting that, we did have incremental depletion, which I'll cover in more detail on slide 19. It's primarily related to lower gas prices and negative price revisions, but I'll cover that in more detail. We had a minor impairment charge related to our UP assets in Colorado. That was $0.12 negative impact to the quarter. And as we highlighted coming into the quarter on our last call that we were going to have stack rig charges. That was $0.11 negative impact to the quarter. And as we recently filed an 8-K, we did have a litigation impact that was $0.03 impact to the quarter. Adjusting for those items, the loss would have been about $0.15.

Moving to the bottom part of the slide and comparing first quarter guidance relative to where we came out, Tim and Scott have both talked about daily production, obviously a good rate relative to where our guidance was set at. Production costs, I've got a detailed slide in the back, but total production costs were down 18% quarter on quarter and 10% on LOE. So the asset team did a tremendous job on bringing our production costs lower during the quarter. Exploration and abandonment costs were $31 million for the quarter, primarily related to acreage costs that we are not renewing, and so that was the biggest piece of that. DD&A I'll cover on the next slide, so I'll hold off on that here. G&A was in the middle of the range. Interest expense was at $41 million, the top end of the range. It's primarily higher than we would have estimated coming into the quarter because it includes $3.5 million of noncash interest related to an accounting change that the FASB implemented January 1 related to how we account for interest on convertible debt. Noncontrolling interest is basically our minority interest, what we've called it in the past, $4 million, where we would have expected it. Rig stack expense came in at $20 million. Current taxes of $10 million, that's all related to Tunisia. And then our effective tax rate was 10% for the quarter and really represents the combination of tax in foreign jurisdictions where we're paying tax offset by a loss in the US, where at a lower rate where we're getting a benefit. And so when the math works out, it comes out to 10% effective rate for the quarter.

Turning to Slide 19, talk about incremental depletion. As most of you know, we do quarterly calculations for DD&A. We update our reserve report at the end of each quarter. When we looked at year end, where we had $5.71 per Mcf gas that we were calculating reserves on relative and rolled that forward to March 31, we used $3.63. As you can imagine the largest impact was in our Raton area which has our largest inventory of gas puds. So when we use quarter end prices, including the differentials we were experiencing in Mid-Continent, most of those puds were uneconomical at March 31 and consequently our depletion rate was increased substantially. We do run an impairment test under successful efforts a little different than the full cost companies and so we didn't have any triggering on impairment charges under successful efforts. But as you can imagine, as long as gas prices remain low, we will have a higher depletion rate going forward. But I would expect that rate to return to more historical levels once gas prices return close to the $5 level.

Turning to Slide 20, realized prices, everybody's aware of what's happened with prices over the last few months, and so if you look at our realized, our reported prices for oil, NGLs, and gas, oil prices were down 5%. NGL prices quarter on quarter were down 26% and gas prices were down 31%. If you look at the bottom of Slide 20, you can see the impact on the two lines -- that's the impact to our derivative positions that -- our derivative positions had on our price realizations. Obviously the switch to mark-to-market accounting is captured in the bottom line, which is not included in our price realizations, but over time it will become a bigger component and the derivative impact included in price will become a minor component.

Turning to Slide 21, oil and gas revenues, you can see we saw another drop mainly of 17% for the quarter relative to the fourth quarter, primarily due to the lower NGL and gas prices we talked about on the prior page. This was offset somewhat by the higher quarterly production that we had for the quarter.

Turning to Slide 22, production costs, here you can see the large decrease that we saw in production costs, down 18% quarter on quarter, 10% on LOE. Tim's talked about in detail the initiatives that the teams have undertaken and what the cost reduction activities have garnered. As you can see in the red box is where we're primarily focused is LOE going down from $8.74 in the fourth quarter to $7.87 per BOE in the first quarter. We also benefited from lower production taxes. And this number, obviously reflective of lower commodity prices, and we did have reduced workover activity during the quarter as well.

Turning to Slide 23, capital spending outlook. As you can see from the slide, we significantly reduced our drilling activity during the first quarter. We had projected for the first quarter to spend about $100 million to $120 million, came in right in the middle of that range at $108 million. And then as you look forward to the second quarter, our activity primarily being focused in Alaska, Eagle Ford frac and South Texas -- Chris talked about and some facility work in Tunisia. So we're estimating that to be $60 million to $70 million in the second quarter and then to be reduced in the third and fourth quarter down to $45 million to $55 million per quarter.

Switching gears for a minute and talk about liquidity, on Slide 24, at quarter end. our net debt was $3.1 billion, debt to book capitalization of 46%, and our credit facility availability was $370 million. This is slightly down from where we were at year end and really should be our high point for the year. I would expect that long-term debt should decrease over the remainder of the year, barring any further declines in commodity prices.

We did amend our credit facility here in April, and so if you turn to Slide 25, I'll give you a summary of where we are in the amendment. The amendment changed our PV to total debt ratio in our covenant from 1.75 to 1.5 times over the next two years. As a technical matter, we did adjust our PV to total debt calculation to receive credit for the PSE MLP units that PXD owns. This wasn't contemplated in our original credit agreement that we did in 2007, and so we thought the amendment was worthwhile to do as a technical matter to include those into the calculations. We also increased the pricing end of the credit facility from LIBOR plus 75 basis points to LIBOR plus 200 basis points and increased our commitment fees of 12.5 basis points to 37.5 basis points, and no change to our debt to book capitalization covenant of less than 60%.

As we looked at it, it's really -- the rationale for it was something we didn't have to do. We had plenty of headroom under our existing covenant and with current bank pricing, but due to the volatility in commodity prices that we've seen, we thought it was prudent to go ahead and do the amendment, just to ensure that we had maximum liquidity if prices were to go substantially lower. And so in return for that, we increased the pricing of the credit facility. As Scott mentioned, we are still very much committed to a free cash flow model and to reducing debt over the next two to three years. And so we would expect over that time period that we would target net debt to book capitalization rate of 35% to 40%.

To that end, turning to Slide 26, we have added new derivative positions since year end and you can see those on Slide 26 here, what we've added. Really the objective of our derivative program is to ensure minimum level of capital for these years so that we can have confidence in returning back to drilling, particularly oil drilling in 2010 and 2011 and also achieve some debt reduction. So as you can see from the slide here, if you add these positions to our existing positions, we have 25% to 30% of our 2010 and 2011 forecasted oil production covered by derivatives and 70% of our 2010 gas production. And we'll continue to monitor the markets and probably add incremental positions in the future as well.

Turning to Slide 27 and going to second quarter guidance, daily production is expected to average 117,000 to 122,000 BOE per day for the second quarter. Production costs are expected to be $12 to $13 per BOE and obviously we're still working to reduce costs and bring those down even lower. Expiration and abandonment, $15 million to $25 million. DD&A per BOE of $16 to $17. This reflects the first quarter run rate and is predicated that we would still expect to have low gas prices at the end of June. G&A, $33 million to $37 million. Interest expense, $42 million to $45 million. This is up from the first quarter, but reflects the new pricing with the amendment to our credit facility. Rig stack charges, $15 million to $20 million. A lot of the rigs start coming off here in the second quarter, so we'll see this amount continue to decline over the year. Accretion discount on asset retirement obligations, $2 million to $4 million. Noncontrolling interest, $4 million to $7 million. Cash taxes, $5 million to $10 million related to Tunisia and then an effective tax rate of 40% to 50%.

Also, I would just point you to Slide 28 and it has the detail of our supplemental schedule , and we encourage you to look at those and review those. With that, we'll conclude my comments and go ahead and open up the call

Thank you. (Operator Instructions). And our first question comes from Michael Jacobs with Tudor Pickering Holt.

Good morning.

Hi, Michael. How are you doing?

Doing well, thanks. Congrats on the quarter. Had a couple of questions. First one on the Spraberry, just wanted to reconcile the 41 wells that you've put online with your 17 new drills. Wondering if you can give us a little insight onto what your backlog of wells [win and] completion are in the Spraberry.

Well, today we have virtually low backlog, essentially zero. As is always the case, Mike, we carry over some wells that were just completed in the sense of drilling at the end of 2008. And some of those get completed into early 2009 actually as to the frac and tying them into production. So we have pretty much now put on all the wells that were drilled last year and the wells were drilled this year on production as we speak.

Okay, great.

We do have some Wolfcamp completions we could look at doing, but today those are being waited on.

Okay. And just a follow-up on the Eagle Ford, one of the things that we didn't discuss, and Chris gave a lot of great operational color, but we didn't talk about the liquids yield that you're seeing as you move from southwest to northeast. And just wondering how you reconcile the net economic impact in the context of producing premium priced liquids with the associated costs of producing from tight reservoirs.

Well, liquids would be a really good thing today. I think it's just a real positive for us. Right now we're producing no liquids, so I don't know what the yield is going to be. Let's just leave it at that. I think what we have seen, again -- the data says we're in an RO value, which is an indicator of thermal maturity that most of our acreage is -- has an RO of 1.5 and greater. So I think we're going to have more dry gas than people are thinking. We will have some condensate. But as I said, liquids would be a pretty good thing today.

Great, thank you.

And our next question comes from Dave Kistler with Simmons & Company.

Good morning, guys.

Dave, how are you doing?

Well, thanks. Looking at the low decline asset base, which performed extraordinarily well this last quarter and looks to continue that trend, was thinking a little bit more about the ramp-up, or ramp back up in production. 2010 forward curve is about $65 for oil. As you talked about, you start thinking about putting more capital to work in 2010. Can you highlight how quickly you think you can ramp up production as you put capital to work? And then I got a follow-on that from that.

With the current strip, it will take us a good three months from the time we start, time we initiate the rampup activity in the Spraberry Trend area. Due to the fact there was hundreds of rigs that are stacked, I think probably the key issue is reattracting the employee base in West Texas to run the rigs. So that's going to be the critical ingredient. Within Pioneer, we can do it fairly quickly, so it's really getting the service companies to ramp up and the availability of employees, so I think with the low decline asset base, you should start seeing some fairly decent response within three to six months after that in regard to production growth. So Alaska will continue to grow.

As Tim mentioned, our Mid-Continent assets will grow with the BBP expiring. Tunisia can get started fairly quickly with successful wells there that come in over 2,000 barrels a day. You could see Tunisia ramp up fairly significantly. And Edwards is probably our best -- Edwards, Eagle Ford are probably our best gas economics that we see improving -- with gas prices at $6 or above upside to $8, we see ramping of activity there fairly quickly.

Okay. That's helpful. Tying that to your stated goal or commentary that you've had about 5% production growth per share going forward, is that the same thing you would be targeting for 2011? And so putting capital to work either in the form of buying back shares against a very flat declining production base, or looking at it in terms of putting capital to work, but staying within free cash flow to keep production per share growing as well?

The 5% is only for 2009. We have not given out any numbers at all in 2010 and 2011 and will not until the end of 2009, early 2010 at that point in time. So obviously the focus is to create a free cash flow model and to grow production per share. We will give out those numbers at the end of 2009, early 2010.

Okay, appreciate that. And then the follow-up question is really just as we look at each one of your respective asset plays, how would you prioritize how you bring them back in terms of Spraberry versus Eagle Ford, Tunisia, Alaska, et cetera?

Obviously with oil trading at -- you take out the differentials right now with gas, oil's trading 20 to 1, so obviously oil gets the main focus. The oil hedges obviously in 2010 or 2011 with upside is where we're doing more derivatives in regard to our three-way collars, so oil is going to be the focus. So Alaska, Spraberry, and Tunisia will be the three key drivers followed by most likely the Edwards play, then Eagle Ford.

Great. I appreciate it. I'll let somebody else hop on. Thanks, guys.

And our next question comes from Xin Liu with JPMorgan.

Good morning, guys.

Hi there.

Good morning.

Question on your Eagle Ford, the second well, you said it's 75 miles south of your first well. And can you point to us which county is it?

Nope, can't do that at this time.

Okay. Can you talk about some results that you have from the private operators out there?

Can you reask the question? Results from where?

Private operators.

Oh, private operators, yes. We're not -- we have a lot of data, but since it hasn't been released, we're keeping that very confidential due to further lease acquisition on our behalf.

Okay. On your Alaska, your estimate net net reserves seemed increased. Can you talk about how much reserves you can book for the next three years?

Yes, we're showing 120 million to 150 million barrels net resource potential. We expect most of that to be booked over the next five to seven years.

Okay. How much do you think you will book this year?

We don't know at this point in time. It all depends on a lot of activity that we're doing in regard to our drilling activity and our frac jobs.

Okay, thank you.

And moving on, we have a question from Brian Singer with Goldman Sachs.

Thank you, good morning.

Hi, Brian.

Picking up on some of the earlier questions, going back to Spraberry, what do you see as the trajectory of production and sales over the next couple of quarters when considering any remaining oil in inventory? I think you referenced there's a relatively low backlog at this point, and then declines?

Well, the normal decline rate -- we have such a large base of 6,000 wells with most of them at a 4% decline rate is that just shows you the benefit of when you stop drilling, you just don't get that falloff. Also we do have -- Tim mentioned we have a backlog. We do have a backlog, I think Michael asked -- about 100 wells. These are Wolfcamp wells that we are delaying completing back into the Spraberry Trend area, including the silt shale zones, and so we can complete those wells. We're delaying completion probably until late 2009, early 2010, but there's a huge backlog of wells. We can open up the Spraberry zones. Then if you look at our historical over the last four years, we're growing it fairly consistently at 15% a year. So our goal is to get up to we hope 8 to 10 rigs in 2010 and ramp it up to 20 to 25 rigs is where we were going in 2009 over a two to three-year timeframe. That's why we're putting in these two year, at least protect the oil prices at least for a couple of years with upside. And that's the goal. The next two quarters, I think it will continue to overperform, just not going to decline that much.

Great, thanks. That's helpful. And second on the Eagle Ford, really thinking strategically about what the Eagle Ford can mean for the company, do you see -- if the play does work in some size that would be completely additive as a new source of investment? Or along the similar questions asked earlier, about whether Eagle Ford will be prioritized, would you then look to replace Eagle Ford on the portfolio and say, sell an asset elsewhere such as maybe the Raton?

Obviously it's not a good time to be selling any kind of asset, especially gas assets. No, that doesn't mean that we can't take capital out of the Mid-Continent area. Maybe Raton. They are our cash cows. We still have a lot of puds left in Raton. They are very, very economical at $6 gas. So I anticipate drilling some wells in Raton going into 2010, but Raton and the Mid-Continent areas could be our cash cows, and we take that cash and basically start up the Eagle Ford if it really turns to be a great growth asset for us. Plus, we've got 200 Edwards wells to drill, too, over the next several years.

Great, thanks. I guess implicit in maybe that comment, when you think about 2010 with improved pricing, is it still a stated goal to spend within cash flow? Or if you see commodity prices rise and financial conditions ease, would you potentially spend a little bit more?

No. Our stated goal has been spend less than our cash flow, reduce debt probably about $400 million over the next two to three years. Right now based on the -- the goal is to do enough hedges in 2010 and 2011 to deliver -- the strip right gives us about $800 million to $1 billion cash flow over the next couple years. The current strip, so obviously we'll have plenty of room to ramp up activity. And then as long as we have these upside in the three ways, it allows to us have cash flow increases of 25% to 30% over and above the swap prices. So we could have cash flows up into the $1 billion to $1.2 billion range. It will give us plenty of flexibility to ramp up our cash flow, reduce debt, so we will continue to underspend cash flow.

Thank you.

Moving on, we have a question from Robert Christensen with Buckingham Research.

How do you plan on fracture stimulating your Eagle Ford shale wells? Is it similar to the way Petrohawk is designed? Is there any differences that you think this shale deserves in the way of treatment than other shales?

Well, our first well, we're doing an eight-stage frac over a 3,000 foot lateral, so there's about 200 to 300 feet in each stage. 400 feet, sorry. Actually, our -- we've met with Petrohawk and talked about completion technique and ours is very similar to theirs.

Does the calcareous nature of the shale give it some advantages, Chris?

I don't know if it gives it any advantages. Really what you're looking for in these shale plays are clay volumes. Lower clay volumes typically are better. Most of the other shale plays have high silica content. The Eagle Ford happens to be more of a carbonate-rich shale. But I don't see there's any kind of real advantage.

Would you ever acidize something like that?

No. Not enough carbonate content.

All right. We'll stay tuned.

All right, thanks.

And we have a question from David Tameron with Wachovia.

Hi, good morning, everybody. Scott, could you talk about as you think about your capital program for this year, is there a -- and I know you guys are being driven by rate of return hurdles -- but is there a level of gas prices we can get to, or oil for that matter, I know you're a little more hedged on the oil side, but -- or gas really on the hedge -- is there a number we can get to where you put capital back to work?

No, not this year at all.

Okay. So you're -- other than the Eagle Ford well, you don't anticipate any ramp at all in activity?

No, not at all. The gas strip right now I think is about $4.30. The rest of the year, it is not attractive returns at that price.

Okay, okay. So -- okay. And then along those same lines, what's the logic in drilling the Eagle Ford this year?

Obviously there is a lot of activity as one question which we didn't answer, there's a lot of private activity. We have some very positive data from some of those private companies that don't announce. We have 300,000 acres. That acreage position expires over the next three to five years. Some of it expires next year.

Okay.

So it's really to plan for the future. It's really a small investment that really focused on some of our key acreage that may be expiring over the next 12 to 18 months to give us a leg up for budgeting capital in 2010.

All right. Just trying to get a recap of the thought process. Thanks.

Okay. And our next question comes from Gil Yang with Citi.

Hi. Could you -- Scott, could you comment on what is the trigger that you're looking for in 2010 that you start drilling then? I know in the previous question, or one of the previous questions, you said there's no gas price that you would start drilling at. But what are you physically looking for in 2010 that triggers you to start drilling more? Is it the hedges, or is it -- ?

Well, it's confidence in obviously what OPEC has done and what the world's economy is doing. Obviously we're much more bullish on crude. Crude is $65 to $66 right now for next year. You can look at our return slides. All Spraberry drilling is very economical with the 35% to 40% cost reduction, which we'll achieve here soon. So it's very, very economical. So it's protecting the cash flow and also protecting the returns from new drilling activity. And having confidence that we're not going to have a second downturn in the world's economy. China and India continue to pick up. US and Europe has stabilized, which will reflect energy demand, which gives confidence in crude prices. So it's a combination of having that confidence in hedging, hedging with an upside.

Okay. So it sounds like within the next few months, it sounds like the costs will be where you want them to be. But you're willing to sit there and not drill for a few months, even though it would be economic to drill for a few months, just to gain cushion so to speak?

Yes, I just don't want to overspend right now. Our cash flow jumps up from $500 million a year up to like I said $800 million to $1 billion next year and that's only because of the forward curve. And so to protect that, you got to protect -- you got to do some aggressive hedging, but do it in a way that gives you upside to commodities. And that's what we're doing. Combined with that, we will start up aggressively drilling in Tunisia and Spraberry and most likely Edwards, and we've already hedged 70% of our gas at $6 or higher with upside up to $8 already in 2010. So what we haven't done is hedged aggressively crude oil yet, so we need to go ahead and finish that more hedging with the three ways that we described to protect the cash flow and start drilling in 2010.

Okay. What is your maintenance CapEx going to be in 2010?

It's about $200 million again. And that's because we get a -- one of the big benefits besides our low decline assets is that we get our Hugoton BPP as Time mentioned rolls off January 1, so we get a big jump in gas production January 1.

Okay.

And Alaska is growing significantly in 2010.

Okay. My last question is about Alaska. What's -- I think before you talked about those wells producing more effectively than you had expected, understanding you had a water problem. Can you comment on the productivity of those wells absent the water issues?

Tim mentioned -- the two wells, we announced that one came in 5,000, one came in 7,000, so we can produce the wells at 12,000 barrels a day. Once we inject enough water in the reservoir to build up reservoir pressure and continue to receive, you got to -- the oil you take out and you got to put in the same amount of water to maintain reservoir pressure. So we hope to get up to 10,000 to 12,000 barrels a day at some point in time.

And your original expectation was 7,000, I think, is that right?

It was about 2,500 barrels a day per well, the initial rate from these two wells, so 5,000 to 6,000. They came in 12,000.

Right, right. And one more question, any update on the Pierre in terms of results?

No, we still have one pretty good horizontal well, one below average. As Tim mentioned, we're updating the model and we'll decide in 2010 whether or not to spend any more capital there.

Okay. All right, thank you.

Okay.

Moving on, we have a question from Kevin Smith with Raymond James.

Hi, good morning, gentlemen.

Hi there.

Had a question. I know there have been some discussion earlier that perhaps DeWitt County had a little bit better permeability than LaSalle, but that looks -- or porosity, sorry, but that looks about the same based on the logs. Is that accurate?

That's right. There's really no difference in -- the porosity values that you see over in the table are total porosity values as opposed to the density porosity curves. I'm showing raw data from the wells.

Okay. And it looks like as we move northeast, obviously we only have two data points -- that the temperature and the pressure is stepping upward. Is that fair to say, or is it just way too early to try and guess?

That's fair to say. We've drilled a lot of Edwards wells and it starts getting pretty hot up there in the far northern regions of our acreage. That's why we stopped picking up things.

Is that meaningfully going to change any of the well costs from the -- McMullen County to do it on up?

No.

Okay.

I mean, that's where we've drilled most of our wells, down into the Edwards. We don't anticipate any problems at all.

And I guess the other question, you talked about holding acreage that expires as early as I guess next year. Is that going to -- you're drilling at Eagle Ford wells, the whole Edwards trend acreage as well?

Not necessarily. There's a couple of areas that are big lease hold blocks that we are obviously trying to protect and evaluate.

Okay, and that would be -- would that be for both formations or just for the Eagle Ford?

Both.

Both formations.

Okay. Thank you very much.

And there are no further questions. At this time, I would like to turn the conference back over to Mr. Scott Sheffield for any additional or closing remarks. Please go ahead.

Appreciate everybody's comments and staying on the call. We look forward to reporting second quarter. Obviously we'll update over the next three months any results from any of our current activities, especially in Eagle Ford. We'll let the market know. Again, thanks. Good morning.

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