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Pioneer Natural Resources Company (NYSE:PXD)

Q1 2009 Earnings Call Transcript

May 6, 2009 10:00 am ET

Executives

Frank Hopkins – VP, IR

Scott Sheffield – Chairman and CEO

Tim Dove – President and COO

Chris Cheatwood – EVP, Geoscience

Rich Dealy – EVP and CFO

Analysts

Michael Jacobs – Tudor, Pickering, Holt & Co.

David Kistler – Simmons & Company International

Xin Lu – JP Morgan

Brian Singer – Goldman Sachs

Robert Christensen – Buckingham Research

David Tameron – Wachovia

Gil Yang – Citigroup

Kevin Smith – Raymond James

Operator

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

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

These risks and uncertainties are described in Pioneer's news release, on Page two of the slide presentation and in 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.

Frank Hopkins

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 will review the financial and operating highlights for the first quarter. We saw Pioneer deliver strong production and great expense performance. He will then comment on the company's outlook for the remainder of 2009.

After Scott concludes his remarks, Tim is 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 has 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 to give you our forecast 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.

Scott Sheffield

Thanks, Frank. Good morning, we appreciate everyone taking time to listen to the call. On our highlights on slide number three, we reported first quarter net loss of about $15 million or about $0.13 per share. We had an after-tax non-cash 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 are drilling now. If we look at first quarter 2008, production was up 15%, again the same key drivers we’ve had Spraberry, South Texas, Edwards play, Alaska Oooguruk project, South Africa and then Tunisia.

We did go here 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 also begin to initiate all derivatives in 2010 and 2011. This strip got up to about $65 and $70 about several weeks ago. In fact, it’s back up there a littlie bit better than that this week. We have hedged about 25% to 30% of our forecasted production. And our strategy here is basically to have a lock in something close to the existing swap price of 65 to 70 in those two years, but give us upside in each of those two years at $80 to $90 a barrel, so using three ways.

Also we continue to hedge more as we see spikes or gas production in 2010, with that upside up to $7.50 to $8.00 in 2010. We now have 70% of our production in 2010 of gas hedged with a swap price roughly about 6, with upside between $7.50 and $8.00. We are continuing to see with our results over the last several quarters, very encouraging results from our Spraberry shale interval testing. We’ve had some areas, which Tim will talk more about areas exhibiting up to 40% increase in production.

Chris will talk a lot more detail about the Eagle Ford Shale. Obviously, we are in the process of frac-ing this week, next week our first Eagle Ford Shale well in South Texas. Also we will 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 cost down over 25%, we expect another 10%, 15% increase. We expect to be 35% to 40% down by this summer. When you couple that obviously with what's happening on crude oil prices, we anticipate obviously starting up drilling aggressively in both Spraberry and also in Tunisia continuing with Alaska program in 2010.

Of course [ph] most important with our announcement is the fact that we want to attribute to Tim, Jay Still, Danny Kellum, all the asset VPs for achieving already the first quarter a large part of their target for the year, 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 four 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 ’09. About 2,500 barrels of that is attributable to NGLs, if you look at foot note number three, make up from the fourth quarter of 2008, but still even if you back those out, we way over performed first quarter ’09 and this shows the quality of our assets in regard to moving the rig count from 30 rigs down to one same time.

Slide number five, on a per share base, continuing to – we had obviously a tremendous year last year of 20% per share. In addition, this year we will be up 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 six in regard to capital spending, it’s important to continue to have free cash flow model, that’s where our CapEx budget between 250 and 300. 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 forecasted capital spending. You can see most of it is oil related 80% and 20% in gas.

Final slide before I turn over to Tim, slide number seven. 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, and obviously very attractive in low commodity price environment. We don’t have to frac the decline curve like a lot of peers.

Our inventory, that’s 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, we continue to take prudent decisive steps to reduce costs and improve returns. And with our hedging, we anticipate starting out substantial rig count obviously in the first quarter of 2010 primarily in the Spraberry field and also in Tunisia.

We will continue to add derivatives in 2010 and 2011 as we have already hedged 25% to 30%. Again, if you look at – it’s really been a great quarter both from production and cost reduction, we will continue that.

Let me turn over to Tim to talk about our specific assets.

Tim Dove

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 as Scott has alluded to both in terms of production and cost savings have shown just that. Our asset teams have done a tremendous job, specifically the Spraberry trend area, South Texas, Mid-Con, all these US assets have had a very good first quarter and have contributed to the overall company’s successful performance on production.

Spraberry is covered more in detail on slide eight. 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. 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 11% compared to – sorry 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 completing in the Wolfcamp, which has been a contributor to both reserves and production, and we continue to see positive results from our non-traditional zones. 2008 and now into 2009 are years where we continuing to make strides in understanding the potential contributions from the shale silty sections they have traditionally not been completed in this favorite trend area. The work we have been doing of course is looking at well pares [ph], looking at wells where we actually completing in the non-traditional sections versus offset wells we were not and trying to get an understanding regarding the impact of the new completions.

We are doing a lot of detailed science work petro fiscal modeling to understand these non-traditional pay intervals and also assessing what is the right proper 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 have seen significant increases in production, some areas 40% or higher than the offset control wells, that’s based on most cases adding additional fracs in the non-traditional zones. And so we might not expect to see that across the entire field, but where we are seeing is giving us enough entry to continue our study at this data. And looking ahead, I think you will see us continue to increase the number of completions in non-traditional zones.

So in conclusion, what we can say is the non-traditional zone work we’ve been doing has been promising in specific areas and with this likely being – requiring additional frac stages in lot of these wells. We did drill 17 wells in the first quarter as a finalized our program and laid the rest of the rigs down. We frac to total of 41 wells, most of those having been done by Raton frac 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 leasehold in drilling at least until we see the cost come down even further. That said, just because of the strong start we’ve got in 2009, we do expect production in this favorite trend to grow about 5%. Again, we are the beneficiary of very low decline rate assets that need low amount of reinvestment especially during these trouble times below commodity prices.

As Scott has already alluded to, we are getting a lot more confidence that we will 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 it will be substantially higher, obviously than we’ve been in 2009. And that’s coming as a 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 we will get further reductions as well.

Turning to page nine, I am going to pass the call over to Chris, as Scott already mentioned, the Eagle Ford Shale has generated a 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.

Chris Cheatwood

All right. Thanks, Tim. As Tim said, in most of comments I will be talking about the Eagle Ford this morning. But I think it’s important that we not overlook what we have accomplished in the Edwards reef trend that directly underlies with Eagle. Also, I will provide this low historical perspective the database that we have in the Eagle Ford.

From 1997 through 2005, we drilled around 80 horizontal wells in 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 per day to over 50 million cubic feet per day. Because of our results and what we learned upon, we began taking up trend acreage in mid-2005 along the Edwards reef play and acquired over 300,000 acres that we still hold today.

In 2006 through 2008, we shut over 900 square miles of 3-D seismic, drilled around 75 wells mostly horizontals and grew production in Edwards outside Pawnee during this time from the previously mentioned 15 million cubic feet per day to over 120 million cubic feet per day. These are gross numbers that I am quoting here. As shown on the slide, that resulted in Q1 ’08 to Q1 ’09 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 drill to the Austin Chalk and the Eagle Ford formations.

We became very interested in the shale formation and gathered information on them as we drilled our Edwards wells. Combining data from the lots and coursing these wells with our expensive 3-D seismic has given us a very good picture of their potential overall acreage. In late 2008, we drilled our first well that has the Eagle Ford formation in Dewitt County. We got a 180 fleet of lower Eagle Ford in the vertical well, and then drilled a 3,000 foot lateral. Completion of the lateral was deferred, so we could incorporate the rock property data from the core. The completion should be done in the next couple of weeks. We will be drilling an 8-stage frac over that 3,000 foot lateral.

We are planning to drill a second horizontal well with Eagle Ford on our acreage in the third quarter. This well will be approximately 75 miles south of the first well. The distance between these wells I think gives you an idea of the scale 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 heard us discuss before, we reduced our capital expenditures across the company. Because of this, production from our South Texas assets is expected to decline in 2009 about 5% relative to ’08.

Turning to slide 10, I will now talk about Eagle Ford play specifics. 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 wet to 250 feet wet. The good average thickness to use and calculate volume metrics is around 200 feet. The effective porosity averages consistently across the area of around 10%. The formation is slightly overpressured with the pressure radiant on 0.65 to 0.7 psi per foot.

One of the most intriguing features across our acreage is the fracturing of the Shale Ford – Eagle Ford in Austin Chalk formations, because we essentially have total 3-D seismic coverage on our acreage, can see fracturing in shallower Eagle Ford and Austin Chalk formations, both on raw seismic data and especially from coherency process. Most of our previously drilled Edwards well had strong mud log shows which frequently require 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 is a natural fracturing of individual well production that recovers, it is difficult to predict until we get multiple test, but it is well known in these types of plays that mother nature's contribution can be far greater than man made horsepower. This could be a great benefit to us both from well performance and reduced in completion cost.

As stated earlier, we have drilled around 150 horizontal wells since 1997. Because of this, we feel comfortable that drilling and completion cost in the long run will average around $6 million. Wells during the initial phase have planned additional cost for science and will probably over designed the completions on the first few wells, but I am confident in our process long term. Most of the questions we feel that today as Frank alluded to earlier would sense how Eagle Ford on our acreage compares to the new discovery by Petrohawk in La Salle County. You can see the location of their acreage on the map relative to our. Their play is slightly different and it is concentrated basically 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 am going to show you well (inaudible). My comments will be brief and you can draw your own conclusions because I think the data speaks for itself. A cross-section on slide 11 shows Petrohawk’s Dora Martin well and La Salle 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 well. All three lags, on all three lags the curve on the left is (inaudible), the center curve is the decreased activity and the right curve is density porosity with density porosity greater than 9% highlighted in pink. I am not sure on the mud loss 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 am sure on merits 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 lag calculated and core data to compare the three wells in areas. I think the data from both the lag and new tables showed all three to be very similar. So I hope this gives you a relative comparison, the one you’ve been looking for. 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 expectations in the Edwards reef play and the Eagle Ford Shale looks very promising. All of our data supports what you’ve heard from us so far about the new play. Also, it indicates our wells to perform similar to the current producers in La Salle County. I look forward to discussing this again with you in the future when we have some shale test results and some higher gas prices.

I will turn it back now to Tim to talk about Alaska.

Tim Dove

Thank you very much. Appreciate that Chris. Yes, 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 rates in plan 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 didn’t meet our production target.

We are going 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 a barrels a day gross and we are now producing as you know about six on a gross basis and such that we have a lot more capability once we get to water injection in place. We do plan and are on target to drill and frac 2 of the Nuiqust production wells during this summer. The frac equipment is on the island ready to go, of course the Nuiqust is the larger of the two reservoirs in the overall Oooguruk development. So it will be very interesting 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 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 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 might sense to do it in this call because if you ever have the right assets for a low gas price environment, the mid-continent assets are Pioneer, just that Hugoton and West Panhandle fields. These are stellar assets with very low decline rate, low reinvestment requirements and our asset teams they have done excellent job in terms of attention to detail to maintain production at a very low decline rate. In addition, this 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 is 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 there. So it gives you an idea of the production is doing very well. And we are not doing any drilling right now, we won’t do any drilling until the conditions for pricing improve, but that said, we are employing the assets in this area and other areas of our field operations. I mentioned earlier the fact that we moved frac fleet Permian to frac wells there and we will 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 are doing a lot of drilling in the Pierre Shale last couple of years. As we are not drilling this year, we are 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 in 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 (inaudible) 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 short a substantial amount of 3-D seismic during 2008 and are right now on the process of evaluating that processing and the objective would be to return to drilling either later this year or into 2010 once the prospectivity from that 3-D has been identified. Production should grow year-to-year about 5%.

South Africa of course we are 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 the year-to-year basis. Overall production for this year from the South Coast Gas Project is expected to be about 30 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 cost 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 cost. As Scott has already alluded the fact that we think our well cost really on an overall average basis across the company would have been reduced about 25% since the peak. We are 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 that was already been mentioned that we will be embarking upon later this year with the idea of having rigs working in January 2010.

Finally, on cost reduction initiatives that are really more focused on production cost, that’s covered on slide 17, our asset teams have done just a phenomenal job of reducing cost and the 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 annual run rate basis of LOE savings this year compared to 2008. And you can already see that showing up on 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 that we already been identified. We have 44 significant projects in six primary expense categories shown on slide 17. I will just cover a couple of things to give you some flavor for the types of things we are doing.

The water disposal and water hauling is very expensive part of our business. We are taking the opportunity this year to improve our efficiencies in that regard, including drilling new water disposal wells in the Raton area. We are now utilizing our own trucks for water hauling in the Permian Basin as oppose to using those of third parties and we are reducing rates on water hauling in the Barnett Shale area to new negotiations. As power and fuel goes, we have new electricity rates that have been put into effect as of January 1 in the Permian Basin and also in the West Panhandle area of Texas that has substantially reduced our cost of energy. And that’s going to be a substantial savings going forward. We are doing a lot this year during the idle time in terms of drilling, in terms of optimizing our compression, in the lot of cases what we are 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 an another example, we continue to push the idea of integrated services even into our Permian operations, where today we have a 15 rig work on our feet pulling units that have an affect eliminated some third-party activities in the field we always have many rigs working just in terms of subsurface repairs. So, surprising to say this is a year where we have heavy attention to detail on all these operational matters and 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.

Rich Dealy

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, kind of going to the most significant one that Scott mentioned we had $75 million mark-to-market gain in the quarter that was primarily to gas prices falling during the quarter and saw derivative position became higher value that was $0.41 of income.

We also had $7 million of Alaska PPT credits come in from $0.04. Offsetting that, we did have incremental depletion, which I will cover in more detail on slide 19. This primarily related lower gas prices and negative price revisions, but I will 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 highlight coming into the quarter on our last call that we were going to have stacked rig charges that was $0.11 negative impact to the quarter, and as we recently filed an 8-K we did have a litigation settlement that was $0.03 impact to the quarter. So adjusting for those items the loss would have been about $0.15.

Moving to the bottom part of this slide and comparing first-quarter guidance relative to where we came out. Tim and Scott both talked about daily production, so obviously a good rate relative to our guidance that was said at. Production costs, I’ve got details slide in the back, but total production costs were down 18% quarter-on-quarter and 10% on LOEs that asset teams did a tremendous job on bringing our production costs lower during the quarter.

Exploration abandonment costs were $31 million for the quarter, it was primarily related to acreage cost that we are not renewing and so that was the biggest piece of that. DD&A I will cover on the next slide, so I will hold up on that here. G&A was in the middle of the range. Interest expense was at $41 million, the top end of the range, is primarily higher than we would have estimated coming into the quarter because it includes $3.5 million of non-cash interest related to an accounting change of the FASB implemented in January 1 related to how we account for interest on convertible debt.

Non-controlling interest was – is basically are minority interest, so we’ve called 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 is all related to Tunisia and then our effective tax rate was 10% for the quarter and it really represents the combination of tax in foreign jurisdictions or revenue-paying tax offset by our loss in the US.

We had a lower rate where we are getting a benefit and so when the math works out, it comes out to 10% effective rate for the quarter. Turning to slide 19 to talk about incremental depletion as most of you know, we do quarterly calculations for DD&A. We update our resolve 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 results on relative and rolled that for the March 31, we used $3.63 and so 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 that we are experiencing in Mid-Continent, you know most of those PUDs were uneconomical at March 31 and consequently our depletion rate would increase substantially. Would you run an impairment test under successful efforts 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 our higher depletion rate going forward, but we would expect that rate to return to more historical levels once gas prices return close to the $5 levels.

Turning to slide 20, realized prices by the way what's happened with prices over the last few months and so if you look at our realized 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 by the two lines, if you add those up, that’s the impact to our derivative positions that we've 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 would become a minor component.

Turning to slide 21, oil and gas revenues, you can see, we saw another drop mainly 17% for the quarter relative to the fourth quarter, primarily due to the lower NGL and gas prices 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 has talked about in detail the initiatives that the teams have undertaken and what their cost reduction activities have garnered as you can see in the red box.

We're primarily focused as LOE going download from $8.74 in the fourth to $7.87 per BOE in the first quarter. We also benefited from lower production taxes, and this number obviously reflected the lower commodity prices and we did have reduced work over 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 $220 million, came in right in the middle of that range at $108 million and then as you look towards – forward to the second quarter, our activity is primarily focused in Alaska, Eagle Ford frac in South Texas, Chris talked about and some facility work in Tunisia.

So we are estimating that to be $60 million to $70 million in the second quarter and then to be reduced in the third and fourth quarter to end at $45 million to $55 million per quarter.

Pushing gears from in 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 your 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, you know borrowing 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.

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 that the amendment was worthwhile to do as a technical matter to include those into the calculation.

We also increased the pricing into the credit facility from LIBOR plus 75 basis points to LIBOR plus 200 basis points and increased our commitment fees from 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 is really the rational for something that we didn't have to do. We had plenty of headroom under our existing covenant and with the current bank pricing, but due to the volatility in commodity prices that we've seen we though it was prudent to go ahead and do the amendment just ensure that we had maximum liquidity if prices where 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 without that time period that we would target a net debt-to-book capitalization ratio 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 a minimum level of capital for these years, so that we can have confidence in returning back to drilling, particularly oil drilling in 2010 and 2007 and also received, achieved 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 I will continue to monitor our – 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 117,000 122,000 BOEs per day for the second quarter. Production costs are expected to be $12 to $13 per BOE and obviously we are still working to reduce cost and bring those down even lower. Exploration and abandon, $15 million to $25 million. DD&A per BOE of $16 to $17, this reflects the first quarter run rate and as predicated that we 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 was up from the first quarter, but reflects the new pricing with the amendment charge 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 will see this and now continue to decline over the year.

Accretion discount on asset retirement obligations $2 million to $4 million non-controlling 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 to slide 28 that has a detail of our supplemental schedules we provide in the back and encourage you to look at those and review those.

And with that will conclude my comments and go ahead and open up the call for questions.

Question-and-Answer Session

Operator

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

Michael Jacobs – Tudor, Pickering, Holt & Co.

Good morning.

Tim Dove

Hi Michael how are you doing?

Michael Jacobs – Tudor, Pickering, Holt & Co.

Well thanks congrats on the quarter. I had couple of questions. First one on the Spraberry, just wanted to reconcile the 41 wells that you put online with your 17 new drills and wondering if you can give us little inside onto what your backlog of wells went in completion are in the Spraberry?

Rich Dealy

Well today we have especially, very low backlog essentially zero. But as is always the case Mike, we carry over some wells that we have just completed, completed the sense of drilling at the end of 2008 and some of those get completed in the early 2009, actually adds sort of frac and timing into productions. So, we have pretty much now put on all the wells that we drilled last year and the wells we drill this year on production as we speak.

Michael Jacobs – Tudor, Pickering, Holt & Co.

Okay great.

Rich Dealy

We do have some Wolfcamp completions we could look at during – today those are being laid up.

Michael Jacobs – Tudor, Pickering, Holt & Co.

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

Chris Cheatwood

Well liquids will be a really good thing today. I think it's just a real positive for us, you know, right now we are producing no liquids. So, I don't know what the yield is going to be like you know let's just leave it at that. I think what we are seeing, example, the data says we are in an RO value, which is an indicator of thermal maturity that most of our acreage has an RO off 1.5 in freight. So, I think we are going to have more dry gas than people are thinking. We will have some condense, but as I said liquids will be a pretty good thing today.

Michael Jacobs – Tudor, Pickering, Holt & Co.

Okay great, thank you.

Operator

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

David Kistler – Simmons & Company International

Good morning guys.

Chris Cheatwood

Dave how are you doing?

David Kistler – Simmons & Company International

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

Chris Cheatwood

Yes. With the current strip it will take us a good three months from the time we start to the time we initiate to ramp-up activity in this scribe rate trend area. Due to the fact there was some hundreds of rigs that are stacked. I think, probably the key issue is, we attracting the employee base in West Texas to run the rigs. So the critical ingredient, within Pioneer we can do it fairly quickly. So it is really getting the service companies to ramp-up and the bell belly of employees, so I think with the low decline of 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 VPP expiring. Tunisia can get started fairly quickly with successful wells there that come in over 2,000 barrels a day. We could see Tunisia ramp-up fairly significantly and average is probably our best average Eagle Ford is probably our best gas economics that we see improving with gas prices six or above, upside to $8 we see ramping up activity there fairly quickly.

David Kistler – Simmons & Company International

Okay that is helpful. Time out to your stated goal or commentary that you guys had about 5% production growth per share going forward, is that sort of 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 decline in production days 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?

Tim Dove

Yes the 5% is only for 2009. We have not given out any numbers at all in 2010 and have been and we will not until at 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 and we will give out those numbers at the end of ’09, early ‘10.

David Kistler – Simmons & Company International

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

Tim Dove

Obviously with all trading at – when you take out the differentials right now with gas oils trading 20 to one, so obviously oil gets the main focus, the oil hedges obviously in 2010 or 11 with upside and that is why we are doing more derivatives in regard to (inaudible). So, all was going to be the focus. So Alaska, Spraberry, and Tunisia would be the three key drivers followed by most likely the Edwards Play and Eagle Ford.

David Kistler – Simmons & Company International

Great. I appreciate and let somebody else hop on. Thanks guys.

Operator

And our next question comes from Xin Lu with JP Morgan.

Xin Lu – JP Morgan

Good morning guys.

Tim Dove

Hi there good morning.

Chris Cheatwood

Good morning.

Xin Lu – JP Morgan

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

Chris Cheatwood

No can do that at this time.

Xin Lu – JP Morgan

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

Chris Cheatwood

Can you re-ask the question, results from where?

Xin Lu – JP Morgan

Private operators.

Chris Cheatwood

Oh private operators. We have lot of data, but since it hasn't been released we are keeping that very confidentiality due to further release acquisitions on our behalf.

Xin Lu – JP Morgan

Okay. On your Alaska, your estimate in that reserve seems increased, can you talk about how much reserve that you can book for the next few years?

Rich Dealy

Yes. We're showing them from 120 million to 150 million barrels in that resource potential. We always expect most of that to be booked over the next 5 to 7 years.

Xin Lu – JP Morgan

Okay. How much do you think you have booked this year?

Rich Dealy

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

Xin Lu – JP Morgan

Okay thank you.

Operator

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

Brian Singer – Goldman Sachs

Thank you good morning.

Rich Dealy

Hi Brian.

Brian Singer – Goldman Sachs

And thinking about some of the earlier questions, and 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 and inventory, I think you referenced that there is a relatively low backlog at this point and then declines?

Rich Dealy

The normal decline rate, we have such a large base of 6000 wells with most of them at a 4% decline rate, is that, but that shows you the benefit Brian off when you stop drilling you just don't get that falloff. Also we do have – as Tim mention 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 this Spraberry trend area including the MCL [ph] shale zones and so we can complete those wells, we are delaying completion probably into late ‘09, early ‘10 but there is a huge backlog of wells, we can open up the Spraberry zones and then if you look at our store goal over the last four years, we are 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 on up top to 20 to 25 rigs, it is where we were going in 2009, over a two to three year time frame. That is why we are putting in these two year at least protect the oil prices released for a couple of years with upside. And that is the goal. The next two quarters, I think it will continue to over perform, just not going to decline that much.

Brian Singer – Goldman Sachs

Great thanks that's helpful. And on the Eagle Ford, really thinking strategically about what the Eagle Ford can mean to the company, do you see if the play does work in some size that that would be just completely additive as a new source of investment or kind of a along some of the similar questions asked earlier about where the Eagle Ford would be prioritized, would you then look to, were (inaudible) referred on the portfolio and say so on assets elsewhere such as maybe the Raton?

Rich Dealy

Obviously it is not a good time to be selling any kind of assets, especially gas assets. The, now that doesn't mean that we can’t take capital out of the Mid-Continent area, maybe Raton, there are cash cows, we still have a lot of PUDs left at Raton, they are very, very economical at $6 gas. So, I anticipate drilling some wells in Raton going into 2010, but Raton in the Mid-Continent could be our cash cows, if we take that cash and basically start up the Eagle Ford with, if it really turns into a great growth asset for us. Plus we got 200 Edwards wells to drill over the next several years.

Brian Singer – Goldman Sachs

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

Chris Cheatwood

No large stated goals has been less in our cash flow, reduced 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, '11, deliver the strip right now gives us about $800 million to $1 billion cash flow over the next couple of years. The current strips, so obviously will have plenty of room to ramp up activity and then if we, as long we have these upside in the three ways, it allows us to have cash flow increases of 25% to 30%, up on about this for prices. So, could have cash flows up into 1 billion to 1.2 billion to arrange. So it will give us plenty of flexibility to ramp up our CapEx, reduce debt, so that we will continue to under spend cash flow.

Brian Singer – Goldman Sachs

Thank you.

Operator

And moving on we have a question from Robert Christensen with Buckingham Research.

Robert Christensen – Buckingham Research

Yes guys, how do you play it on stocks factors stimulating your Eagle Ford shale wells, is it similar to the way Petrohawk is designed, is there any differences that you think the shale deserves in the way of treatment that other shale’s I guess?

Chris Cheatwood

Well first of all, we are doing and eight states frac over 3000 collateral. So, it is about 200 to 300 feet in each stage, 400 feet sorry. Actually we met with Petrohawk and talked about completion techniques and ours is very similar to theirs.

Robert Christensen – Buckingham Research

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

Chris Cheatwood

I don't know if it gives any advantages, really the, what you are looking for in these shale plays is clay volumes, lower clay volumes typically or better. You know mostly the other shale plays have high silica constant, the Eagle Ford happens to be more of the carbon acreage shale, but I don't see it has any kind of real advantage.

Robert Christensen – Buckingham Research

Would you ever acidize something like that?

Chris Cheatwood

No, not enough carbonate content.

Robert Christensen – Buckingham Research

Okay. All right we will stay tuned.

Chris Cheatwood

All right thank you.

Operator

And we have a question from David Tameron with Wachovia.

David Tameron – Wachovia

Hi good morning. Scott could you talk about, do you think about your capital program for this year, is there a, I know you guys are being driven by rate of return hurdles, but is there a level of gas prices that we get to, will you put – oil for that matter, I know most of it are hedged on oil side, but more gas related were un-hedged, is there a number we can get to where you put capital back to work?

Scott Sheffield

No not this year at all.

David Tameron – Wachovia

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

Scott Sheffield

No not at all. On the gas stripe right now I think is about 430 the rest of the year, it is not attractive return to debt price.

David Tameron – Wachovia

Okay. And then along with the same line, what is the logic in drilling the Eagle Ford this year?

Scott Sheffield

Obviously, that is a lot of activity as one question, which we didn't answer, there is 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 them expires next year. So, it is really to plan for the future. It's really a small investment that really focuses 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.

David Tameron – Wachovia

All right. Just trying to get a little capital thought process. Thanks.

Scott Sheffield

Okay.

Operator

And our next question comes from Gil Yang from Citi.

Gil Yang – Citigroup

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 you, or one of the previous questions you said there is no gas prices you would start drilling at. But what you are specifically looking for in 2010 at triggers you just start drilling more, is it the hedges or is it –?

Scott Sheffield

Well it is confidence and obviously, but OPEC has done and what the world's economy is doing. Obviously, we are much more bullish on crude. Crude is 65, 66 right now for next year. You can look at our return slides. All Spraberry drilling is very economical with the 35%, 40% cost reduction, which we will achieve here soon. So, it is very, very economical. So it is protecting the cash flow and also protecting returns from new drilling activity and having confidence that we are not and have a second downturn in the world 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 is combination of having that confidence in hedging, which is edging with an upside.

Gil Yang – Citigroup

So, it sounds like you within the next few months, let’s say, it sounds like the cost would be where you want them to be, but you're willing to sit there and not drill for a few months even though would be economic to drill for few months just to gain a little bit of cushion so to speak?

Scott Sheffield

Yes I'm just doing overspend right now in 2000 and our cash flow jumps up from $500 million a year up to like I said $800 million to $1 billion next year. That is only because of the Ford cover. And so to protect that you got to protect, you got to do some aggressive hedging, but doing in a way that gives you some upside to commodities, that's what we are doing. And combined with that we will start up progressively drilling in Tunisia and Spraberry and most likely Edwards and we've already had 70% of our gas at $6 or higher with upside up to $8 already in 2010. So, what we haven't done and is hedged aggressively crude oil yet. 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.

Gil Yang – Citigroup

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

Scott Sheffield

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

Gil Yang – Citigroup

Okay.

Scott Sheffield

And Alaska is growing significantly in 2010.

Gil Yang – Citigroup

Okay. My last question is about Alaska, what I think before you talked about those wells producing more effectively than you would had expected, understanding you had a water problem, can you comment on the productivity of those wells absent the water issues.

Scott Sheffield

Yes, 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 if we – 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.

Gil Yang – Citigroup

Your original expectation was 7, I think, is that right?

Scott Sheffield

It’s about 2,500 barrels a day per well, the initial rate from these two wells, so five to six and they came in 12.

Gil Yang – Citigroup

Right. One more question, any update on the Pierre in terms results?

Scott Sheffield

No, we still have a one pretty good horizontal well, one below average as Tim mentioned, we are updating the model and we will decide in 2010 whether or not to spending more capital there.

Gil Yang – Citigroup

Okay. All right. Thank you.

Scott Sheffield

Okay.

Operator

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

Kevin Smith – Raymond James

Hi, good morning gentlemen.

Scott Sheffield

Hi.

Kevin Smith – Raymond James

I 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 I guess based on the logs. Is that accurate?

Chris Cheatwood

Yes, that’s right. There is 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 am just showing raw data from the wells.

Kevin Smith – Raymond James

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

Chris Cheatwood

That’s fair to say we are – 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.

Kevin Smith – Raymond James

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

Chris Cheatwood

No.

Kevin Smith – Raymond James

Okay.

Chris Cheatwood

That’s where we drilled most of our wells, down into the Edwards. We don't anticipate any problems at all.

Kevin Smith – Raymond James

And I guess the other question you talked about holding acreage that expires, as early as I guess next year, is that going to be you are drilling and Eagle Ford wells to hold Edwards Trend acreage as well?

Scott Sheffield

Not necessarily. So, here it is couple of areas that are big leasehold blocks that we are obviously trying to protect and evaluate.

Kevin Smith – Raymond James

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

Scott Sheffield

Both.

Kevin Smith – Raymond James

Both formations. Okay thank you very much.

Operator

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.

Scott Sheffield

We appreciate everybody’s comments standing on the call. Look forward to reporting at second quarter. Obviously, will update over the next three months, I mean any results from any of our current activities especially in Eagle Ford and let the market know, again thanks. Good morning.

Operator

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

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