Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message| ()  

Executives

Frank E. Hopkins - Vice President, Investor Relations

Scott D. Sheffield - Chairman and Chief Executive Officer

Timothy L. Dove - President and Chief Operating Officer

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

Analysts

Michael Jacobs - Tudor, Pickering, Holt & Co.

David Kistler - Simmons & Company International

Joseph Allman - JPMorgan

Gil Yang - Citigroup

Brian Singer - Goldman Sachs

Leo Mariani - RBC

Pioneer Natural Resources Co. (PXD) Q4 2008 Earnings Call February 4, 2009 10:00 AM ET

Operator

Welcome to Pioneer Natural Resources' Fourth Quarter Conference Call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors 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-K or excuse me, 10-Q or 10-K made with the Securities and Exchange Commission.

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 E. Hopkins

Good day, everyone. And thank you for joining us. Let me briefly go over the agenda for today's calls. Scott's going to be the first speaker. He will discuss the financial and operating highlights for 2008. He will then comment on the company's capital spending plans for 2009 which were targeted at delivering free cash flow.

After Scott concludes his remarks, Tim is going to review the performance of our assets both for 2008 and the fourth quarter. And then he will talk a little bit about expectations here going into 2009, particularly in light of the current economic downturn.

Rich is then going to cover the financial highlights from the fourth quarter. He will talk about our year-end liquidity position and he'll finish up with guidance for the first quarter. And after that as usually we'll open up the call for questions.

So with that I'll let Scott kick it off here.

Scott D. Sheffield

Yeah, thanks Frank. Good morning.

On slide number three, the 2008 Highlights, the company reported a net loss for the quarter of $65 million or $0.57 per share, unusual items of $48 million or $0.42 per share. We grew production toward the high end for the quarter, for our guidance 118,000 barrels of oil equivalent per day, we're up 14% over the last 12 months, quarter-to-quarter.

Obviously, the biggest growth coming from our core assets the Spraberry, Raton, South Texas, Edwards play, Alaska and Tunisia, they are up 20% over the same time period the last 12 months. Produced 41.5 million BOEs in 2008, on a per share base that we are up over 20%. And, on an absolute base we were 17%.

We already have released our proved reserves and also our refining cost metrics. We had a tremendous year adding proved reserves of a 110 million BOEs. Reserve replacement 250% primarily from drilling success and performance improvements. If you really three small acquisitions during the year. We did have negative price revisions, 69 million BOEs and we had discussed that we get most of that back in a $60 plus oil price environment.

Drillbit, one of the best years we've had, we had $13.80 in regard to our drillbit finding cost for 2008 excluding price revisions. All in finding cost of $13.26 excluding those price revisions. Including price revisions little bit over $35 per BOE. Most of the price revisions that we've discussed earlier primarily related to oil.

We did liquidate oil and gas derivatives primarily oil for 2009, 2010. At PXD we use the proceed during the fourth quarter to buy debt somewhere between $0.65 and $0.30 on a dollar and also buyback shares. We reduced our shares down to 114.5 million shares in 2008 and our goal is continue to reduce that overtime.

Our net debt-to-book been reduced from 48%, 12 months ago to 45% a year in '08. We're still targeting to move that down further overtime. We have $541 million available on unsecured senior credit facility. And we're in total compliance with our debt covenants as we have stated in the past.

We implemented new oil and gas derivatives for 2009. Most of the gas derivatives are around 615 per Mcf and most for all derivatives are around $52 primarily to protect cash flow. We do expect a rebound going back into 2010. So at this point in time do not expect to do much hedging for 2010 and after... in regard to the commodities.

Flipping to slide four, Operational Update, I think the biggest event for the fourth quarter is that through a series of actions over the last 12 months we are able to get approval by all operators in the Spraberry Trend area, in addition to Texas Railroad Commission in regard to down spacing on 20-acre spacing. And all during the year we began the first part of the year in 2008. We had excellent results in regard to performance, performing very similar to 40-acre drilling in regard to our 20-acre drilling. Also our shale interval testing, obviously we have found that over the last 30 years, we have not been opening up additional pay zones.

Tim will talk more about it, but we've been opening up additional shale still sounds in the Spraberry Trend area. We tested... done some testing with those by themselves and got very encouraging results. In addition, we're finding out that the Spraberry as you go deeper, we had a very significant Pennsylvania Discovery coming in over 600 barrels a day.

Moving to Pierre Shale, we announced that we were drilling two horizontal wells, we completed those two wells. I think the most important thing is that the first well has been producing almost 90 days. It's broken over much faster than we had thought in regard to hyperbolic decline curve. We'll show our range later on that it's targeted about 2 Bcf originally, but has a potential. And then based on current performance it could get up to 3 Bcf to 4 Bcf. That's by the most encouraging part of the horizontal well that came in about 3 million a day.

In addition toward the end of the quarter; in finishing up Edwards drilling, we added another two discoveries with additional 3-D, we felt like that we found another 150 Bcf resource potential as these fields are probably most likely connected as we will drill starting in late 2009, early 2010 and start proving this build up. Very little reserves are booked with this. So again additional reserves that we can meet booking in 2009.

In addition in the same area, and where we feel like as a sweet spot, very comparable to Petrohawk's recent two discoveries. In regard to the Eagle Ford Shale we completed our 3,000 foot lateral. We did call it, we're analyzing it and we will frac that well next month in March, expecting tremendous results from this well in the Eagle Ford Shale play.

Also we had very nice surprise toward the end of... actually in early January, with the 7,000 barrel a day well. In Oooguruk, in regard to that an additional 3-D seismic that we had evaluated. We've increased our resource potential as Tim will talk about 50% in regard to our Oooguruk resource potential in regard to Alaska.

Also in this environment, what's most important is that we're implementing significant cost reduction in regard to this low commodity prices and we'll continue to do so both on the well cost, operating cost and on the G&A side.

Slipping... going to slide number five, really a five and six just emphasize the fact the quality of our assets can deliver consistent production growth as it has over the last four years; 2005 to 2008. And also on a per share base which we think people will need to look at on a production per share base we delivered somewhere between 17% to 20%. Obviously, in a low commodity pricing market with our assets having pretty much a flat production profile. Over the next several years that we can continue to grow on per share base of 5%.

Slide number seven, again just to re-emphasize the fact our F&D that we released earlier, we ended the year pretty much flat with last year. But that's primarily due to the 69 barrel of oil revisions that we run, the new SEC rules. We have got all that back, then expect to get it back over the next couple of year as crude gets up to 60 or higher.

That would have put us away over a 1 billion barrels in regard to total reserves of the company. Again we added 102 million barrels or close to 250%. Pretty much spread at all of our key assets, that said negative revision primarily were affected in our oil related properties primarily Spraberry.

Great F&D for us, reserve mix pretty much stayed the same, R/P ratios stays about the same. In regard to CapEx moving forward we've been very aggressive over the last three months and we are continuing to reduce CapEx. We are down... essentially we'll be down by mid-February to about three rigs; two in Spraberry, drilling primarily Wolfberry wells, and one in Alaska.

Total capital spending of about $250 million or $300 million. Obviously we'll be generating free cash flow. We'll talk about the uses of that, and we do expect similar finding cost of between $10 and $15 with this capital, primarily coming from Spraberry Trend area, some Edwards and then also Alaska as we see in 2009.

Slide number nine, our Cash Flow Profile. Again I have emphasized the fact that we have cut our CapEx down to a point where we have free cash flow from operations, net of capital. We are valuating obviously to increase financial flexibility, increase NAV per share. We're about evaluating volumetric production payments primarily on the use of the... take an advantage of the lower interest rates, in regard also to the gas strip in Contango significantly, and with reducing differentials over the next several years.

And also looking on evaluating the use of a drop down into Pioneer's Southwest Energy Partners of up to $200 million. Uses obviously, continue to improve financial flexibility at debt, ability to buy debt as we see it fluctuate and by G (ph). Then also secondly continue to reduce shares.

Slide number 10, Investment Highlights; again highlight the fact that we have probably the longest R/P ratio of almost anybody out there, low decline rates, very low decline, our normal decline rates somewhere between 6% and 8% with no investment. But be able to what's nice is that we can keep production flat for next several years spending very, very little money.

We have a huge drilling inventory, huge resource potential. We'll be getting back up... I'm confident that we'll see a $60 and $6 gas price an oil price environment in 2010. So I expect us to ramp back up to at least 15 rigs sometime in late '09 early 2010.

Continuing to improve our financial flexibility, we think it's important to deliver free cash flow in '09 and beyond. I think it's important to continue to reduce cost at all levels, improve returns.

And I think finally, is that we have definitely the cheapest stock trading at $4.75 per BOE on proved reserves, total enterprise value. As our recent announcement of running sensitivity cases we're trading at 60% of PV-10 at pretty much strip pricing. Long-term strip pricing is about $70 oil and $7 gas.

Let me stop there. And turn it over to Tim.

Timothy L. Dove

Thanks Scott. As Scott has already alluded to, we have taken some pretty dramatic steps and I think aggressive steps towards the positive in terms of reducing spending across the company's operations and to give you a feel for that we were about 29 rigs last summer.

The peak of our drilling campaign, we were eight by the fourth quarter. And as Scott has alluded to be we'll be about three by mid-February. And what that means is that the company is going to be very focused on production maintenance in 2009. And with equal footing we'll be working very hard on cost reductions both on the drilling side and on the LOE side.

And we have of course, excellent assets to pursue that kind of strategies based on slide 11. Spraberry is probably the quintessential asset in a low commodity price environment owing to its low decline rates from existing wells. That said the company's assets in Spraberry did very well in 2008 as we have a larger drilling campaign of 370 wells.

Production in the fourth quarter was up about 4% compared to the prior fourth quarter and other than for the hurricane effects, we were earlier discussing in prior conference calls, we now have reestablished production at about 33,000 BOE per day in mid November, and that's approximately the current run-rate. But overall, production grew about 13% in the year.

In 2009, of course, we are going to be reducing the rig count, and the two Scott already alluded to that down from last year's peak of about 17. And this asset can continue to grow even with that limited amount of spending. We think it's about 2% plus again owing to the long life nature of the reserves and the relatively low decline rate that comes from that.

On slide 12, this is an update as to the tremendous resource potential that we think is still there of course, this low price environment does nothing in terms of affecting all the oil in the ground other than waiting for it to come out. And we still believe we have 1 billion BOE of potential in this recourse base.

And we continue in some our initiatives on focusing on that resource base. And the whole effort of course is focused on increasing the expected recovery per section in the field. And toward that end in 2008 we did drill 18, 20-acre wells with the idea of focusing on that 20-acre campaign. We have 12 of those currently on production. And the results are very encouraging. In fact, these wells are very similar to their offsetting 40-acre locations. And continue to give us confidence in the 20-acre campaign looking forward where we think we have some 9,500 drilling locations, when economics improve.

We are also continuing to work on our waterflood, we're in the midst of designing a template for how we are going to pursue water flooding in some of our unit areas. And we will evaluate the number of injectors and producers that will be put in place. We are locating where those wells would go, the spacing, the number of wells and so on. Most of the campaign I believe based on what's going on with commodity prices. And spending on this campaign will be pushed probably mostly to 2010.

We do have now a couple of wells as Scott has alluded to in our shale silt program that are producing from isolated zones, non-traditional zones. In fact, a couple of these wells we've purfed in the areas we took that we had not done so on all the traditional wells over many, many years. And in each case we have about 20 barrels of BOE bases per day from those isolated zones. And that gives us a lot of confidence that, we have the potential to add really to our resource potential from this because it is not currently in that 1 billion barrel resource potential number.

We're also combining production from the traditional zones and the non-traditional zones to assess what will be the combined effect by purfing all from down the intervals. And we've had some success in horizontal drilling as we alluded to you in 2008. Of course that activity has been somewhat curtailed in the current environment. And nonetheless, we've seen some positive results and think horizontal drilling has metric to add stability in field looking forward.

We think there is still significant potential on our acreage for deeper zones including the Wolfberry. I will talk more about that in a minute, but specifically we did make a interesting discovery in the Pennsylvanian about a 600 barrel a day oil on IP and as it stabilized at about 300 barrels a day.

Interestingly it's already produced about 40,000 barrels since over the last four months or so. We need to do further testing on this area and determine what the play is going to develop as but it gives you the concept that the deeper drilling in the Sprayberry is going to produce some benefits looking forward.

Slide 13, this is a slide specifically regarding the Wolfberry, the deeper trend, a play where we've had a great deal of success. You can see on the map that we have a large number of wells that are Pioneer wells that have IP-ed over 100 barrels a day in the periphery acres East and West, which is we think more prolific for the Wolfberry.

We tend to see EURs of these wells of a 120,000 to 150,000 BOE per day. And accordingly we have a large inventory up and down in this swap of acreage for current end feature drilling. A significant portion of our wells we'll drill this year and looking forward we'll be targeting these higher EUR areas.

Slide 14, is really depicting the economics of the Wolfberry drilling, the higher EURs, 120,000 to 150,000 BOE, tend to yield as you might expect significantly better returns on the basis of the higher EUR. And suffice it to say these wells were typically being drilled about $1.5 million in the middle part of 2008 during the peak. We think those cost have now dropped about 20% to about $1.2 million it should be represented by the red curve.

We're targeting an additional decrease of some 15% to 20% down to about $1 million per well. And if we're able do to that and getting back to Scott's comment on a $60 and $6 case, you can see with a pretty substantial economics. And it could allow us to get back to drilling if we are able to reduce the oil cost on the one hand and have confidence in a sustained $60 and $6 case.

Turning to slide 15, this is as a news obviously here in the Raton area particularly related to Pierre but, this is another excellent asset, a low length asset that allows us to weather the commodity price storm that we are in. And must we'll gain owing to the fact we have relatively low decline rates in this long life field.

Production was up in the fourth quarter about 7%, over the prior year and it grew overall in the year about 16%. We had a pretty large drilling campaign in 2008. Today, we're curtailing drilling in light of the current environment. That said we still expect production to only decline about 5% in 2009. But of course we're evaluating increasing drilling in the same vein as we were discussing on Spraberry with an improvement in commodity prices.

Slide 16, this is really the news item of the day in terms of the Raton area that is the results from two horizontal Pierre shale wells that we recently completed to head on production now for several weeks. We drilled two horizontal wells in each case keeping within the KP1 zone, the deepest horizon in the shales. The two wells as depicted on our acreage which is shown in the green outline are about 10 miles apart to give you an idea of the aerial extent of the these two horizontal wells. And they have been oriented more towards the deeper part of the basin where we think the KP1 is even more prolific.

As shown in the boxes the Jackknife well and the Hawaii wells are both drilled about 2000 foot lateral lengths. And importantly, what we are looking for are mineralized fractures, open fractures in the horizontal plain and interestingly on the one well to the North and the Jackknife well we had almost 2.5 times as many fractures about 600 fractures are seen in the logging suites. And the result of which is we had a much better well there with an IP of about 3 million a day, and as Scott as already alluded to upside to some 4 Bcf in that well.

Hawaii well we saw a less fracturing and but we still saw a very good well flow rates of 1.5 million a day which should be somewhere in the neighborhood of double, we'll expect in the vertical well, even in a well which was not as prolific as our best well. We do have 15 vertical wells drill producing and they continue to track the type curves that we have established in some of our prior publications.

One of the things we are trying to do now of course is evaluate these wells and evaluate potential use of micro seismic to optimize the future drilling and the idea here is coupling micro seismic with existing 2-D to improve your fracture mapping, so you can optimize locations for future drilling, and improve our understanding of the fracture orientation in the field. So that's the work we're going to be doing in 2009 in preparation for ramped up drilling program when commodity prices improve.

Slide 17, Edwards. Edwards had a really tremendous year, when you consider 41% production growth. We had two excellent new discoveries, together they represented about 70 Bcf of resource potential. And with new 3-D seismic in some other areas, we think the total resource potential we have added is some 150 Bcf.

We had a pretty active drilling campaign last year. And in addition to which we closed a bolt-on transaction during the fourth quarter, very good transaction, it's along the lines of many good bolt-ons we've done in the campaigning in all of our core areas. In this case it's about $40 million transaction, it adds substantial acreage in the Eagle Ford Shale not withstanding the Edwards Trend acreage with about 60 drilling locations in the Edwards, about a $1.50 per Mcfe prove. So really an excellent bolt-on.

We are maintaining a low campaign of drilling, we're finalizing the drilling campaigns coming out of last year we have no rigs currently running. And anticipate that will be the case until we see improvement in gas prices. We think the production will decline year-to-year about 5% in Edwards if we did not do any more drilling that is currently planned.

The Eagle Ford Shale, of course is shown on slide 18, is an important growth area, in a sense that we have about 310,000 acres under lease, it just happens to coincide with the Edwards Trend acreage as shown on yellow on slide 18. We even have acreage, it's very close to juxtapose to the Petrohawk recent discoveries. In fact, in a couple of cases we've got 15,000 acres juxtaposed about a mile away from the more Southwest of the Petrohawk wells. And, we've got about 6,000 gross acres about 8 miles away from where the next completion is expected. So we'll probably be pursuing some drilling in these areas looking ahead.

Notwithstanding that we would believe, that our acreage in general will have equal prospectivity to some of the results you're seeing with Petrohawk, and we'll be pursuing that looking ahead. And we have as Scott has already mentioned, one well, we drill a 3,000 foot lateral along. But right in the midst right now, as we're evaluating the core and these objective being properly design the frac for this well which is anticipated at the end of March or into early April. But this is something looking ahead that has substantial resource potential, and we think can really grow our South Texas operations.

Slide 19, Alaska has been exceptionally well in 2008 meeting all of the production forecasts. And anticipated growing through time, as we continue to drill wells. One recent well is important in the sense we've had an IP raised about 7,000 barrels a day gross on this well better than anticipated. And it could potentially even increase or raise the growth of production we'll get that kind of high quality well results.

In addition, to which we're going to take one of the producing levels which is really drilled as an injector and converted into our injection has been currently producing for few months. And so that will be one of the operations we'll perform surely. We are drilling, we're drilling right through the downturn here in Alaska, where it really make sense to do so.

Really important aspect of Alaska is the fact we've substantially increased our resource potential to up to 120 million to 150 million BOE, it was about 70 to 90. And what this is, is a product of a lot of work done by our Alaska team. And what we're reflecting here is opportunities that are reachable from the existing island or from our nearby shore acreage that we've evaluated from our recent 3-D issues.

Also this gives us a lot of anticipation for the future on Alaska. Looking at that kind of resource potential, today we want book 10 million barrels in Alaska to give an idea of the potential for reserve bookings and resources looking ahead.

Slide 20, Africa. A summary of both South Africa and Tunisia. South Africa, of course we have turned around the most prolific South Coast Gas well to gas production. Really, on target with about 70 million cubic feet a day. Increasing as we get into the second quarter to about 80 million to 90 million cubic feet per day. And in doing so we'll be increasing the gross production but the same time reducing cost because we no longer have the Sable oil FPSO on the field and accordingly our margins will improve significantly.

In Tunisia, we had a very good year about 54% production growth compared to 2007. We had a fourth quarter production about 8,000 barrels a day up substantially of course from fourth quarter we're drilling throughout the year.

And in addition to which our current gross production in that area is about 34,000 BOE per day. We have interest of course in various blocks, they are producing today. We're going to curtail production in Tunisia after a couple of activities we're performing now, until we finish an evaluation of our 3-D and until essentially in this case oil pricing improves to justify drilling.

We continue to work on our feet study, we should move gas from the Southern part of the country to the Northern markets with other industry players. And hopefully can pursue that through the year and point towards the project as we get into the early part of next decade.

And finally, in terms of my slide, slide 21. I mentioned, the offset we have got a substantial amount of effort that's going on today in terms of an equal weighting on cost initiatives with production maintenance. And just give you a few examples here shown on slide 21, we already believe we've got about a 15% to 20% reduction in well costs, as of the end of the year and we are targeting another 10% to 20% reduction. We are trying to be thoughtful here in terms of utilizing our own company owned facilities. In fact, we have frac fleet we've moved on from Raton to Spraberry. So we are not using any outside parties, now we are using all internal equipment in the work we doing so as to save cost. Just another example, this is just one example but we are very focused on the details here and example may be designing our team made slurries to cut cost in our Raton operation.

So we are very focused on this in addition to which we are heavily focused on reducing

LOE per BOE. Of course we want to work on the denominator here to some extent to. And so we are focused on production from current wells, to give you an idea we've have selective 1650 well grouping that we've increased production over the last 12 months some 7% to 9%.

So we are very focused on the details of the nuts and bolts of current production especially during this downturn. And we are going to be the beneficiary of having renegotiates some of our electricity contracts, very substantial savings there. Really going to be focused on all the details of production and where those costs that run up till the last couple of years including water hauling, due to cost of fuel and so on.

And we're really just focus as a sale on every aspect of optimization in these fields whereas compression or rig optimization or reducing water production we have here. In addition, to which we've got a very significant G&A initiative underway as well. So again an equal weighting if you will between cost reduction initiatives and maintenance of production.

So with that I'll pass it to Rich for a discussion of the fourth quarter and the financials.

Richard P. Dealy

Great, thanks Tim.

Turning to slide 22, we did report our results for the fourth quarter as a $65 million loss or $0.57 that did include a number of unusual items that totaled up to $0.42 or $48 million. Looking at the slide there kind of briefly go through each one of those, the gain on bond repurchases we did buy a $107 million of face value of bonds during the quarter and recognized $23 million gain in interest net income with respect to that on a pre-tax basis.

As we've projected in our third quarter call, we did have termination and stack charges and so we had total rig related charges of $40 million for the quarter in other expense. Well, I will talk more about the ongoing affect of that in 2009 when I get back to guidance.

Acreage abandonments we have some acreage that we did write-off that were not renewing leases given the current price environment for about $25 million for the quarter, that was a non-cash charge. In Mississippi we did impair our asset there due to lower gas prices so that was $15 million non-cash charge for the quarter.

We had mark-to-market derivative loss of $11 million for the quarter once again non-cash in the sense that these are hedges that we put on in December and prices a little bit higher year-end, so we had a mark-to-market charge related to that, obviously they're in money today.

We also took a $10 million charge related to our East Cameron 322, remediation project that was a platform toppled in Hurricane Rita, that's to increase the final cost of get that all cleaned up. I think the key point there is that, that charge is still substantially covered by insurance. That we'll get back in a future quarter. So adjusting for those items, the loss for significant unusual items was $0.15.

Looking at the bottom of slide 22, just our performance relative to our guidance as Tim and Scott both mentioned we are at the high end of production so the assets continue to perform very, very well. Production costs I have got another slide on that but we are at the fine end of the range but inside the range. And I'll talk about that in a minute.

Exploration and abandonment came in at $56 million in the middle of guidance range and primarily related to the acreage charge I talked about earlier and seismic activity that we are finishing up in Tunisia and South Texas during the quarter.

DD&A $14.76 above the range mainly because of the lower year-end pricing that we didn't anticipate we're in seating in November. And so that it caused some... the negative price revisions that we've talked about and caused our DD&A rates to be a little bit higher.

G&A was inside the range of $38 million, interest expense the same $40 million, rig termination and stack expense at $35 million, was slightly below the range mainly just because we are able to not terminate some of the rigs that we thought we might terminate in stack them instead.

Current taxes, we do have a benefit of $9 million for the quarter, related to the loss and effective tax rate of 26%.

Turning to slide 23, talk about our realized prices as everybody is aware about the commodity prices, fell dramatically in the fourth quarter, oil prices, our realized price were down 32% relative to the third quarter on oil, 50% on NGLs and 22% on gas. Gas kind of have the double impact that we projected when we talked about our earnings for the fourth quarter in our third quarter call where now when we do have lower gas prices but significantly wider differentials.

And for the fourth quarter differentials are wider by about $0.68 relative to the third quarter. We did benefit in the standpoint of NGLs and gas from our hedge positions where we did pick up some $1.17 on NGLs and $1.45 per Mcf on gas in the fourth quarter.

Turning to slide 24, just gives you a picture of the substantial decrease in revenues that we saw on the fourth quarter. We are down 26% from the third quarter and as mentioned previously its really reflective of the lower commodity prices and higher basis differentials on gas but they don't grope the decrease. Obviously, production was up and they as such continue to deleverage just the pricing was not the same.

Turning to slide 25, on production costs for the fourth quarter we were down $0.16 per BOE relative to the third quarter. As you see on the yellow bars on slide 25, production tax we saw a substantial decrease in production taxes primarily related to commodity prices. If you look at the red border our base LOE, you can see that we did see a cost reduction relative to the fourth quarter. So probably, the turning point in terms of our cost reduction initiatives is getting underway. And I think probably to a larger extent lower energy related cost in terms of electricity and fuel charges in the fourth quarter.

Now, this was offset by increased natural gas processing expenses for those of you who are aware we do process third party gas under percentage of proceeds contract in the number of our producing areas that we have spare capacity. That allows us to pick up some incremental revenue and fully utilize our facilities. But as NGL and gas prices fall, our profit margin on that third party gas that we processed goes down as well. And so we had a net $0.96 expense for the quarter related to net cash processing activities.

I think the key point here as Tim mentioned and went through in detail that we do expect future production costs to benefit from our cost reduction initiatives. And we'll... you expect to see that continue as we move through 2009 and make further improvements.

Turning to slide 26, really just gives you a reflection of our capital spending by quarter in 2008 but really the... more important is what we're forecasting by quarter for 2009, as Tim and Scott, both talked about we have... end of the year with nine rigs we're reducing it by mid-February to three rigs.

So our first quarter CapEx plan is going to be a little front-end loaded relative to the rest of the quarters for the year. But once we get passed mid-February, our activity is going to be focused on Alaska and Spraberry and that will be the two areas that we've got the three rigs running.

Turning to slide 27, liquidity position you can see from the timetable there, we don't have any near-term maturities coming due. You can see in the charts that we did update the new face value of each of the bond reflecting the recent repurchases as we did in the fourth quarter.

We did exit the year at net debt at $2.9 billion as Scott mentioned, debt-to-book capitalization of 45% down from 48% a year ago. And we're looking at the credit facility; we are in compliance with all of our covenants and we've got $541 million of liquidity, so plenty of liquidity out there.

In terms of total overall debt we are, as Scott mentioned longer term looking to reduce that debt more to 35% to 40% of debt-to-book capitalization something that we'll be focusing on with the free cash flow model that obviously helps there.

Turning to slide 28, and talk about first quarter guidance, production expected to be 117,000 to 122,000 per BOE, I mean BOEs per day in the first quarter. Production cost, you can see here do reflect that we expect them to be down relative to the fourth quarter based on our cost reduction initiatives.

Exploration and abandonment $20 million to $30 million down from the historical level reflection of reduced drilling activity that are going on. DD&A $13.25 to $14.25 per BOE. G&A $32 million to $36 million, interest expense $38 million to $41 million.

We are forecasting still rig termination and stack charges in the first quarter of $25 million to $30 million. We would expect those to decline through the year, a lot, most of those rigs now come of. Those contracts in mid-year and so we'll see second quarter at a little lower rate than our substantial lower rate in the third and fourth quarter. Cash tax is expected to be $5 million to $10 million mainly once again just Tunisia where we expect current cash taxes and an effective tax rate of 40% to 50%.

Turning to slide 29, just a listing of supplemental schedules we have in the back for your review. And so, I'd encourage you to look at those and run through those, when you have time. But at this point we'll like to go ahead and open up the call for questions.

Question-and-Answer Session

Operator: Thank you. (Operator Instructions). We'll take our first question from Michael Jacobs with Tudor, Pickering, and Holt.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Good morning, gentlemen.

Scott Sheffield

Hi, Michael.

Michael Jacobs - Tudor, Pickering, Holt & Co.

I'd like to kick it off with a few questions on the Spraberry Trend area and then a high level question. You've seen better economics in the Wolfberry, you've got pretty exciting results from what looks to be the strong and when we went back in September we discussed the potential of numerous producing zones for well in the ultimate development plan. When you think about your revised plan with too many rigs, how do you expect to drill and complete future wells?

Scott Sheffield

Obviously, we're in a $35 to $45 oil price environment and anybody that's drilling today, the new volumes coming out obviously are not hedged. Even though we are heavily hedged at $52 for this year, it's economical in the Wolfberry. But any new volumes we're... the only reason we're running two rigs is really just to protect the... we've some large leases in the Wolfberry that we cannot get extensions on. So it's economical, long-term I am confident that crude is going to get back some where between $60 and $80 over the next 12 months. Confident that our well cost will come down somewhere between $700,000 and $900,000 in a say a lower price environment.

And we'll be back to somewhere between 8 - 12 rigs by early 2010. So the program well just reached our back up, most of our acreage locations is held by production and that's what not as you can shut off the switch, invest capital wisely, via sale volumes at $40 to $44 and let sell them next year at $60, $65, $70 so that's the game plan.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Okay. And for Scott and Tim, if we think about the typical Spraberry well recovering 100,000 barrels from three to four zones for roughly a 1 million today. If we think about 40,000 to 50,000 per stage what incremental recoveries do you expect if you add in additional let's say six to eight different zones?

Scott Sheffield

Well, our Wolfberry slides are in there, there are 120,000 to 150,000 barrels per well. That's somewhere between a six stage and a ten stage frac. All we're doing now is opening up a couple of new shale zones that's what Tim talked about and they're making about 20 barrels a day.

And so that's generally about 40% a third to 40% of a total well production. So we are starting to open up all those zones in them in our 20-acre and 40-acre drilling that we completed in the fourth quarter. So we'll see those results as we produce these wells out as we complete in first quarter and second quarter especially of last year's activity. So we do expect as Tim mentioned to increase the resource, 1 billion barrel resource based on those results.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Great. One last question on the Spraberry you are seeing a lot more companies really test and explore acres these days just to get a better understanding of how to optimize the development plan and maximize returns. Can you offer some insight as to how you think about development versus exploration in this environment? Obviously, you're holding some acres in the Wolfberry but any insight as to what you're doing to test it and better crack the code would be useful?

Scott Sheffield

We think it's important as we have seen in the Raton probably we will have a tendency during this downturn to own more and more equipment, in regard to pumping service, we've seen the benefit only on pumping services.

We've seen the benefit owning our own, a lot of our frac equipment, frac tanks pulling units, work over units. We've seen huge payouts one to two year payouts. So we'll probably do more of that in the future. Also, we will continue to look at leases in fact a lot of our budget is picking up more renewing leases but also picking up some more opportunities of people that can't drill in regard of the Wolfberry and some other areas.

So we will continue that. But we've done enough, we pretty much have defined a pretty good area where most of these, the better Wolfcamp wells are with the Spraberry Trend area. So we are also excited about upside potential in the Great Berg San Andreas (ph) and also in Pennsylvania as we seen more, more prospects with our work.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Okay. One final question before I pass this. We take a step back and try to get an understanding of how you allocate returns, Scott can you walk us through how you make the decision to allocate capital between repurchasing debt at $0.65 on the dollar versus buying back stock or planning capital into the ground. And may be if you could give us an insight on how those discussions took place internally that will be helpful?

Scott Sheffield

Yeah, obviously, if you are trading at $4.75 per BOE when you got free cash flow that's an excellent place to be putting your money something's that probably worth in the $12, $13, $14 range per BOE. At same time you've got to improve financial flexibility. But the debt, our debt got down to, some of our debt instruments got down to $0.60 - $0.65 on the $1, $0.68 on a $1. So that's a tremendous return.

And so, at $4 gas and $44 crude, I'm surprised there is really any rigs running in the U.S. market. So it's obviously a lot of reasons, why a lot of rigs are running. But at current oil and gas prices very few of them should be running. Because most of that product is not hedge, is coming out of the ground. And so it's not very economical that we do in any drilling at this point in time.

Michael Jacobs - Tudor, Pickering, Holt & Co.

Okay. So if we assume weaker prices persist, can you reconcile how you think about absolute production growth versus production per share growth in 2010?

Scott Sheffield

Yeah, I mean, going forward we have such a unique asset basis that we can essentially keep production flat. But we want three to four years and basically buy in 100% on the shares and keep debt flat slightly declining. So that's obviously with an asset base like this, that's one opportunity with the market cap as low as we have today.

In regard to the returns have to exceed the value of our stock, Then we expect to get back to those top returns in 2010. I think all over reset significantly over the next nine months. Gas may be a little bit different story, the reason we mentioned VPP is simply because a strip is $6.50 to $8 over the next seven years. Also the differentials narrow by 50% in almost all categories. So it allow us to take an advantage of that. So--

Michael Jacobs - Tudor, Pickering, Holt & Co.

Okay. Thank you very much.

Operator

We'll take our next question from David Kistler with Simmons & Company.

David Kistler - Simmons & Company International

Good morning, guys.

Scott Sheffield

Hi, Dave.

David Kistler - Simmons & Company International

Quick question about the credit facility or the borrowing base there, with positive reserve revisions everything within covenants. Any thoughts on what you expect that to look like going forward my guess would be the big variable would be the pricing, commodity pricing that the banks are using?

Scott Sheffield

Yeah, I've got no the banks... the oil and gas industry is in very good shape. They have a lot, lot other that have issues, so I'm not going to predict what the banks will or will not use. Its going to be pretty much predictive on the forward strip, the forward strap is going be very indicative of what banks tend to use as long the forward strip stay strong in both commodities, the banks are going to stay with their standard price sticks.

David Kistler - Simmons & Company International

Okay. And I guess the rational for asking the question is following up a little bit on Michael's comments on paying down debt versus buying back equity. Trying to get a sense for what kind of fire power you'd have on a capital standpoint to be able to ramp up production or CapEx spending and following that production in kind of 2010 or late 2009 if we start to see commodity prices correct, can you just kind of walk us through how you think about all those things?

Scott Sheffield

Yeah, our slide shows that if we do something on the slide, I think its 8 or 9 on cash flow uses in 2009. Obviously, it implies doing both when 2010 comes along, we want to make sure that we have reduced shares and we want to make sure that we have improved financial flexibility. I can't tell you specifically how much will go to each, but that's the... at the end of the day we want to have improved financial flexibility and want to have a lot less shares by the end of 2010... 2009.

David Kistler - Simmons & Company International

Okay. Diving into cost cutting measures and you discussed G&A initiatives, can you give us some more color on that kind of headcount areas that you'd be looking at cutting back any kind of additional clarity there would be very helpful?

Scott Sheffield

Yeah, we're talking about a 10% to 20% reduction in our... as you see our G&A come out over the next several quarters.

David Kistler - Simmons & Company International

Do we know what that equates to from a headcount standpoint?

Scott Sheffield

No, most of the headcount will be more related to consultants in regard to obviously we're not drilling so a lot of headcounts has been reduced there, primarily consultants but the rest of is other things that we're doing internally.

David Kistler - Simmons & Company International

Okay. Great I appreciate that. I'll let somebody else hop on.

Operator

We'll take our next question from Joe Allman with JPMorgan.

Joseph Allman - JPMorgan

Yes, thank you, good morning, everybody.

Scott Sheffield

Hi, Joe.

Joseph Allman - JPMorgan

Scott, of the 69 million BOE of negative price related revisions how many of those were PD and approved developed tails versus spud tails versus just part of eliminations?

Scott Sheffield

Most of that was all related and most of this was due to the oil price and most of was in Spraberry and most of was PDP.

Joseph Allman - JPMorgan

Okay. Great, helpful. And then how about the positive revisions could you talk about those?

Scott Sheffield

Yeah they were pretty much all areas, Spraberry, Alaska, Raton, Edwards.

Joseph Allman - JPMorgan

Okay, very helpful.

Scott Sheffield

Now, one thing to note is that as I had talked with you about a year ago on... I don't know if that was mentioned but we do our 20-acre drilling that was put into the positive revisions it did not go since 20-acres in infield drilling and sort of existing field. We did books some 20s and that went into positive revisions.

Joseph Allman - JPMorgan

Okay, got you. That's helpful, and then how many 20-acre locations you have booked at this point?

Scott Sheffield

I am guessing out of 15,000 somewhere between and 200 and 300.

Joseph Allman - JPMorgan

Okay. Got you, okay it's helpful. And then looking at the same kind of rate of return for the Wolfberry I mean if you just look at kind of the more shallow Spraberry look on if you are using say $50 oils, $6 gas, $60 oil it's the same price that you gave, what kind of rate of return do you see for the more shallow Spraberry?

Scott Sheffield

The Wolfberry were about 35% at $50 and $6 and the shallow Spraberry will be more like 20 to 22 to 24 in that range.

Joseph Allman - JPMorgan

Okay, that's helpful. And then that--

Scott Sheffield

There is a return slide, Frank just mentioned that in our slide in the back we didn't go over our return slide to various prices.

Joseph Allman - JPMorgan

Okay, that's helpful. Thanks. And then with deeper Pennsylvania zone that you have some... a good result there, what's the repeatability of that and what is the formation there?

Scott Sheffield

Yes, the Pennsylvanian we are not commenting into the sensitive nature of it right now. And we'll be offsetting this location towards the later part of the year. So we don't know how big it is at this point in time.

Joseph Allman - JPMorgan

Okay, al right. And then with the Pierre Shale first two horizontal what's the cost per well there?

Scott Sheffield

Our goal is to get the cost down around $2.5 million per well and if we can deliver 3 Bcf, 2.5 Bcf - 3 Bcf or higher, that's very, very great returns. So obviously, our costs are a little bit higher on these initial wells. Because they were drilled during the high part of the season. But we feel like that we can get cost down to about $2.5 million on a horizontal well total.

Joseph Allman - JPMorgan

Okay. And then the verticals, what are the costs there for the verticals and EUR there?

Scott Sheffield

EURs we've been during the back of our slide I think they are around 700 million to 750 million, 0.7 by Bcf and cost around 900 and 950,000 and we think we can get them down even further from that.

Joseph Allman - JPMorgan

Okay. And then lastly just the rig count, you are still dropping some rig, what's the rig count now, just onshore U.S. and--

Scott Sheffield

We are going to drop in one more... Spraberry rigs will be down to two as Tim mentioned, and one Alaska. So three rigs.

Joseph Allman - JPMorgan

Got you, okay, very helpful. Thank you very much.

Operator

We will take our next question from Gil Yang with Citi.

Gil Yang - Citigroup

Hi, good morning Scott.

Scott Sheffield

Yes, hi, Gil.

Gil Yang - Citigroup

Can you give any reasoning why your Oooguruk wells the 7,000 barrels per day, produced better than you would expect to?

Scott Sheffield

Well, we didn't comment on when we brought on our first well, it came on much better than expected. We just, we wanted to watch it to make sure and our second well came on 40% barrels in that well. So we decided obviously, with 3-D seismic to up the resource potential.

We felt fairly good over the last six to nine months watching the start-up of the Oooguruk. We've seen the improvement of Alpine which is similar, ConocoPhillips and then Anadarko. They've gone to frac jobs also. There is two zones and there is one zone that we're going to be fracking later this year. So based on resulted Alpine, we think that Oooguruk is going to be a lot bigger 2 to 3 times the size they initially came out with. So just getting much better permeability, much better porosity than we thought. I am glad our people were conserved going into it.

Gil Yang - Citigroup

Okay. So its sound like it's a combination of better reservoir and better fracking?

Scott Sheffield

Also the better the 3-D seismic when we improve this we do not have 3-D seismic. The ConocoPhillips had the only 3-D seismic, and getting that and evaluating it has helped this project significantly. And so we can target our wells much better. And, so we're seeing that the sizes of the field is much bigger based on that 3-D seismic.

Gil Yang - Citigroup

Okay, all right. For CapEx, you commented on I think you couldn't keep productions stay in 2010. Any sense for what CapEx what level you would need in 2010 to do that?

Richard Dealy

Yes, I think we stated that the last three months of about $200 million.

Gil Yang - Citigroup

For 2010?

Richard Dealy

2010 also. Yes.

Gil Yang - Citigroup

Okay. You kind of enter to 2011?

Richard Dealy

Well I have said, basically we can buy an 100% of the stock over the next three to four years and keep production flat, barely flat may be a 2% decline in '11, '12 over the next four years. There was not much drop off.

Gil Yang - Citigroup

So, I'm under the impression that for 2009 and 2010 some... lot of your growth is coming from Oooguruk and I guess Tunisia initially and South Coast gas so it's sort of you are running out the momentum you've build up over the last few years. And so am I wrong about that and if I'm not wrong then would you--?

Scott Sheffield

One of the thing that helps us in 2011 and '12 is that we have 13,000 barrels a day coming back on from VPPs.

Gil Yang - Citigroup

Okay.

Scott Sheffield

So that's a big help in those years.

Gil Yang - Citigroup

Okay. Combined for those two years, right?

Scott Sheffield

That's combined. We have 13,000 barrels a day coming back on over the next three years, starting in 2010 through 2012.

Gil Yang - Citigroup

Right, right. And then finally, if you are using your own rig fleet it's almost exclusively now how are you going to squeeze in those 10% to 20% of cost?

Scott Sheffield

No, we're using our own frac fleet.

Gil Yang - Citigroup

Frac fleet, okay.

Scott Sheffield

Okay. So it's only our frac fleet that we are using. Generally if you own your own equipment in a downturn what we're seeing is that the service companies are predictable in the next three to six months we'll get down to bear bones where they are losing money in regard to certain activities. So when you own your fleet you don't make any money. It's really the up cycles where you would own your own equipment that you save a lot of money.

So the additional cost savings will be for instance, like our Spraberry drilling contracts expire in April and June. We're hearing rights of already somewhere between 8,000 and 10,000 a day for a 1000 horsepower rig or less and we're paying about roughly $12,500 to $15,000 on these last two rigs.

Steel costs are coming down significantly. So those are the two big items. So the frac fleet we're using our own equipment now. So it's come down, its already build in, its saving us a lot of money but the stimulation companies are starting to get down to where they are losing money just to keep equipment running and also people employed.

Gil Yang - Citigroup

All right. Thanks a lot Scott.

Operator

We'll take our next question from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Scott Sheffield

Hi, Brian.

Brian Singer - Goldman Sachs

Wanted to check in on backlog on both the oil and the gas side if you look to lower 48 onshore, how much production do you have behind pipe or are waiting completion?

Scott Sheffield

Yes, I'm surprised by the comments that I have seen a lot of people are doing that. Most leases in the U.S., most royalty owners do not allow you to unless it's on a held by production lease. So we have zero, very little and so the articles that I have seen in new releases you can not drill a well and leave it shut in, you'll loose your lease. And so its got be on held by production leases that people are doing at. So I don't understand the companies that are doing that you really have to ask them.

Brian Singer - Goldman Sachs

Okay. And I guess the flipside is when you do start drilling again if commodity prices improve would you expect an immediate production ramp or is there some delay that one should expect?

Scott Sheffield

It will be a lag period of about at least three months. Obviously, in South Texas with the top of the wells that we make 8 million to 10 million a day, you'll see a big ramp up there. In Spraberry, it will be a slower ramp because the type of well. Raton will be a slower ramp so it varies by area.

Brian Singer - Goldman Sachs

Okay. And then lastly, on the Pierre, Eagle Ford and Edwards, what gas price would you need to see to get more aggressive in drilling is that the $6 or there different numbers for those three basins?

Scott Sheffield

I'm going to say $6 with the appropriate well cost that we see are coming done. We will definitely get more aggressive.

Brian Singer - Goldman Sachs

Otherwise it would be a higher gas price today but with your expectations for falling well cost, you think that get it down to $6?

Scott Sheffield

Exactly and also improve differentials, the differentials have widened out. You can see on... we didn't talk about them but we have hedged at least half of the differentials. The differentials blew out again the last two weeks in regard to Permian, Barnett Shale, Mid-Continent, Rockies. And say we are trying to prevent that blow out is basically we've already hedged half the differentials this year. We are hedging aggressively over the next two or three years differentials.

Brian Singer - Goldman Sachs

Have you seen any examples or at is there a point that you would shut an existing production?

Scott Sheffield

No.

Brian Singer - Goldman Sachs

Thank you very much.

Scott Sheffield

Sure.

Operator

Thank you. We will take our next question from Leo Mariani with RBC.

Leo Mariani - RBC

Hi, good morning, guys. Just looking for a little bit more data on your Alaskan oil wells, that recent you guys bought on 7,000 barrels a day. How long has that been on production in what kind of declines do you see in some of those older wells over this?

Scott Sheffield

Well, it's simple we have seen zero decline in a well just tested last week. So don't have any history but obviously Tim, talked about the injection what's important when you are producing these type of rates, you need reservoir maintenance. And so that's why we're converting one well to injection as soon as possible. So it's all about recovery. So... but the first well we've seen essentially no decline for several months. First set of wells.

Leo Mariani - RBC

Okay. Jumping over to Spraberry, obviously you guys have been testing some of interbedded silt stones there and shale the formation was a pretty good result. Just to make sure I understood some of your earlier comments. Are you guys basically, co-mingling (ph) with some of the traditional Spraberry stands own then looking to have some results the next four, five months that we stand out there?

Timothy Dove

Yes, exactly. I guess it's the first question.

Leo Mariani - RBC

Okay.

Scott Sheffield

Yes, you are allowed co-mingle all zones. You can co-mingle in a Spraberry from Clear Fork all the way down to the Wolfcamp.

Leo Mariani - RBC

Okay. Question with respect to your production guidance in 2009 you talked about having flat production with relatively limited CapEx when you say flat production is that flat to your first quarter guidance to that 117 your 122 numbers throughout the rest of the year, just trying to make sure I understood your comment there.

Scott Sheffield

No, it's calendar year to calendar year.

Leo Mariani - RBC

Okay. Thanks a lot guys.

Scott Sheffield

Okay.

Operator

We will take our next question from Ray Deacan (ph) with Fischer Capital.

Unidentified Analyst

Yes, question for Tim, I guess did you combine the new hedges that you did with bases hedges and can you just remind me how I know you tend to get a better than Rockies prices in the Raton where would you expect to be able to lock that in for the next year or so?

Timothy Dove

Yes, as Scott mentioned half of the gas we have locked into differentials favorably compare specially compared to history. We have overtime Ray (ph) as you know in a sense of return on assets price to gas they are in Mid-Continent markets. Mid-Continent markets did never very good, we are on there at the end of 2008 and have blown out a little bit since then but my recollection is our current hedge position vis-à-vis in the Mid-Continent is about $1.20 on there is that right, Rich?

Richard Dealy

For '09 and--

Timothy Dove

For '09.

Richard Dealy

sub 90 for 2010.

Unidentified Analyst

: Got it. Great thanks very much and is in the budget that you have adopted for '09 will you be going back into drill additional horizontals in the Pierre or is that 2010?

Timothy Dove

Well, today we are sort of evaluating as I mentioned in my comments. What the next direction vis-à-vis to sell fracture patents, the fracture orientation. So we have got a little science work to do. So I would anticipate to the extent we drill later in the year perhaps it will be end of 2010.

Unidentified Analyst

Okay, got it. So you're doing micro seismic?

Timothy Dove

Right. Micro seismic will take quite a long time to get done.

Unidentified Analyst

Got it. Okay, thanks very much.

Operator

We'll take our next question from Joe Allman with JPMorgan.

Unidentified Analyst

Well, it's actually Shinu (ph) for Joe Allman. On your reserve you have some positive technical revisions, can you give us a idea what percentage is from infield revision?

Scott Sheffield

Yes, I don't have that exact data, I can get Frank Hopkins to call you back on that after the call.

Unidentified Analyst

Okay, thanks.

Operator

And it appears we have no further questions at this time. Mr. Hopkins I would like to turn the conference back over to you and the presenters for any additional or closing remark.

Frank Hopkins

Okay. Again we appreciate obviously hope everybody have seen that we have a great set of assets, we're monitoring through this downturn. We are going to get through it and 2010 and going forward the company is going to be obviously showing strong growth again. So focus on increasing financial flexibility and reducing shares and reducing costs is our current focus. Preserving the value for the shareholders. So again thanks and look forward to you in the next earnings call.

Operator

Thank you, ladies and gentlemen. Once again that does conclude today's conference. We thank you for your participation.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Pioneer Natural Resources Q4 2008 Earnings Call Transcript
This Transcript
All Transcripts