先鋒自然資源 (PXD) 2008 Q4 法說會逐字稿

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

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

Good day, everyone, and thank you for joining us. Let me briefly go over the agenda for today's call. Scott is going to be the first speaker. He will discuss the financial and operating highlights for 2008. He will then comment on the company' capital spending plans for 2009 which are 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 will finish up with guidance for the First Quarter, and after that, as usual, we'll open up the call for questions. So with that, I'll let Scott kick it off here.

Thanks, Frank. Good morning. On Slide 3, 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 of our guidance, 118,000-barrels of oil equivalent per day or up 14% over the last 12 months quarter to quarter.

Obviously, the biggest growth coming from our core assets of 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 BOE's in 2008, on a per share base we were up over 20% and on an absolute base we were up 17%. We already have released our proved reserves and also our finding cost metrics, we had a tremendous year adding proved reserves of 110 million BOE's. 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 of 69 million BOE's 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 drillbit finding costs for 2008, excluding price revisions. All in finding cost of $13.26, excluding those price revisions. Including price revisions, a 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 and we use the proceeds during the Fourth Quarter to buy debt somewhere between$0. 65 and $0.70 on the dollar and also buy back shares. We reduced our shares down to 114.5 million shares in 2008 and the goal is to continue to reduce that over time. Our net debt to book has been reduced from 48% 12 months ago to 45% at year-end '08. We're still targeting to move that down further over time.

We have $541 million available on our 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 $6.15 per MCF and most of our oil 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 4, operational update. I think the biggest event for the Fourth Quarter is that through a series of actions over the last 12 months we were able to get approval by all operators in the Spraberry Trend area in addition the 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 out over the last 30 years we have not been opening up additional pay zones. Tim will talk more about it but we're opening up additional shale silt zones in the Spraberry Trend area. We've done some testing with those by themselves and have 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 we're drilling two horizontal wells. We completed those two wells. I think the most important thing is that the first well had been producing almost 90 days. It's broken over much faster than we had thought in regard to a hyperbolic decline curve and we show a range later on that it's targeted at about two Bcf originally but has a potential, and based on current performance, it could get up to 3 to 4 Bcf. That's probably the most encouraging part of the horizontal well that came in at 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 3D, we feel 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 field up. Very little reserves are booked with this so, again, additional reserves that we can be booking in 2009. In addition in the same area and what we feel like is a sweet spot, very comparable to Petrohawk's recent two discoveries. In regard to the Eagle Ford Shale, we completed our 3000-foot lateral. We did core it and 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 a 7,000 barrel a day well in Ooguruk. In regard to that, an additional 3D seismic that we've evaluated. We've increased our resource potential ,as Tim will talk about, 50% in regard to our Ooguruk 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 the low commodity prices and we'll continue to do so both on the well cost, operating cost, and on the G & A side.

Going to Slide 5, really 5 and 6 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 need to look at on a production per share base. We've delivered somewhere between 17% to 20%. Obviously, in a low commodity price market with our assets, having pretty much a flat production profile, over the next several years that we can continue to grow on a per share base of 5%.

Slide Number 7, again, just to re-emphasize the fact of 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 million barrel of oil revisions. If we run the new SEC rules we've got all that back -- expect to get it back over the next couple years as crude gets up to $60 or higher. That would have put us way over a billion barrels in regard to total reserves for the Company. Again, we added 110 million barrels or close to 250%, pretty much spread out all of our key assets. Our negative revisions primarily were affected in our oil related properties, primarily Spraberry.

Great F&D for us. Reserve mix pretty much stayed the same. RP ratio stays about the same. In regard to CapEx moving forward, we've been fairly aggressive over the last three months and we're continuing to reduce CapEx. We're down essentially -- we'll be down by mid-February to about three rigs, two in Spraberry drilling primarily Wolfberry wells ,and one in Alaska, and total capital spending of about $250 million to $300 million. Obviously, we'll be generating free cash flow. We'll talk about the uses of that. And we do expect similar finding costs of between $10 and $15 with this capital, primarily coming from the Spraberry Trend area, some Edwards and then also Alaska, as we see in 2009.

Slide Number 9, our cash flow profile, again I've 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're evaluating, obviously, to increase financial flexibility, increasing AV per share. We're evaluating volumetric production payments primarily on the use of the taking advantage of the lower interest Slide Number 9, our cash flow profile, again I've 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're evaluating, obviously, to increase financial flexibility, increasing AV per share. We're evaluating volumetric production payments, primarily on the use of the taking advantage of the lower interest rates and in regard also to the gas drip in Contango significantly, and with reducing differentials over the next several years. And also, looking on and evaluating the use of a drop down into Pioneer Southwest Energy Partners of up to $200 million. Use is, obviously, to continue to improve financial flexibility and debt, ability to buy debt as we see it fluctuate and buy it cheap. And then also, secondly, continuing to reduce shares.

Slide Number 10, investment highlights, again highlight the fact that we have probably the longest RP ratio of almost anybody out there, low decline rates, very low decline. Our normal decline rate is somewhere between 6% and 8% with no investment. We can be able to -- what's nice is that we can keep production flat for the next several years spending very, very little money. We have a huge drilling inventory, huge resource potential. We'll be getting back -- I'm confident that we'll see a 60 and 6 gas price in oil price environment in 2010, so I expect us to ramp back up to at least 15 rigs some time in late '09, early 2010. Continue to improve our financial flexibility, 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.

Thanks, Scott. As Scott has already alluded to, we have taken some pretty dramatic steps, and I think aggressive steps, toward 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, at the peak of our drilling campaign. We were eight by the Fourth Quarter and, as Scott has alluded to, we'll be about three by mid-February. And what that means is 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 strategy.

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 had 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 that 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're going to be reducing the rig count down to 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 pricing environment does nothing in terms of affecting all of 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 resource base, and we continue in some of 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 look very encouraging. In fact, these wells look 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 9500 drilling locations when economics improve.

We're also continuing to work on our water flood. We're in the midst of designing a template for how we're going to pursue water flooding in some of our unit areas and we're evaluating the number of injectors and producers that will be put in place, we're 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 into 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 perfed in the areas we typically have not done so on all of the traditional wells over many, many years and in each case we have about 20-barrels BOE basis 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's 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 perfing all up and down the intervals.

We have had some success in horizontal drilling as we alluded to in 2008. Of course, that activity has been somewhat curtailed in the current environment but, nonetheless, we've seen some positive results and think horizontal drilling has some applicability in the field looking forward. We think there is still significant potential on our acreage for deeper zones including the Wolfberry.

I'll talk more about that in a minute. But specifically, we did make an interesting discovery in the Pennsylvanian. It's about a 600-barrel- a-day well, an IP, and has 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 Spraberry is going to produce some benefits looking forward.

Slide 13, this is a slide specifically regarding the Wolfberry, the deeper trend, the 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'd over 100-barrels of day, in the periphery acreage east and west which is we think more prolific for the Wolfberry. We tend to see EURs of these wells of 120,000 to 150,000 BOE per day and, accordingly, we have a large inventory up and down this swath of acreage, for current and future 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 at about $1.5 million in the middle part of 2008 during the peak. We think those costs have now dropped about 20% to about $1.2 million, which would 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 were able to do that, getting back to Scott's comment on the 60 and 6 case, you can see we would have pretty substantial economics and which would allow us to get back to drilling if we're able to reduce the well cost on the one hand and have confidence in a sustained 60 and 6 case.

Turning to Slide 15, this is some news obviously here in the Raton area, particularly related to Pierre, but this is another excellent asset, a long life asset that allows us to weather the commodity price storm that we're in and, again, owing to the fact that 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 and that said, we still expect production to only decline about 5% in 2009. We'll, of course, be 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 and had on production now for several weeks. We drilled two horizontal wells in each case, keeping within the KP-1 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 these two horizontal wells. And they've been oriented more towards the deeper part of the base in where we think the KP-1 is even more prolific.

As shown in the boxes, the Jackknife well and the Hawaii wells were both drilled about 2000-foot lateral lengths and, importantly, what we're looking for are mineralized fractures, open fractures in the horizontal play and, interestingly, on the one well to the North and the Jackknife well, we had almost 2.5 times as many fractures, so about 600 fractures is seen in the logging suites. And the result is we had a much better well there with an IP of about 3 million a day and, as Scott has already alluded to, upside to some 4 Bcf in that well. Hawaii well we saw less fracturing and we still saw very good well of flow rates of 1.5 million a day which would be somewhere in the neighborhood of double what we expect of a vertical well, even in a well which was not as prolific as our best well. We do have 15 vertical wells still producing, and they continue to track the tight curves that we've established in some of our prior publications.

One of the things we're trying to do now, of course, is evaluate these wells, evaluate the potential use of microseismic to optimize the future drilling. And the idea here is coupling microseismic 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 of the field. So that's the work we're going to be doing in 2009 in preparation for a 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 3D seismic and some other areas we think the total resource potential we've 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 Company in all of our core areas, in this case about a $40 million transaction. It adds substantial acreage in the Eagle Ford shale, notwithstanding the Edwards trend acreage with about 60 drilling locations in the Edwards. About $1.50 per Mcf proved, 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% at Edwards if we did not do any more drilling than is currently planned. The Eagle Ford shale, of course, is shown on Slide 18 is an important growth area in the sense that we have about 310,000-acres under lease, just happens to coincide with the Edwards trend acreage as shown in yellow on Slide 18. We even have acreage that's very close to and juxtaposed to the Petrohawk recent discoveries. In fact, in a couple cases we've got 15,000-acres juxtaposed about a mile away from the most southwest of the Petrohawk wells and we've got about 6,000 gross acres about eight 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 seen with Petrohawk, and we'll be pursuing that looking ahead and we have ,as Scott has already mentioned, one well, we drill a 3000-foot lateral on. We're right in the midst right now of evaluating the core and the objective being to 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 done 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 had an IP rate of about 7,000 barrels a day gross on this well better than anticipated, and it could potentially even increase our rate of growth of production where we get that kind of high quality well results. In addition to it, we're going to take one of the producing wells which has really drilled as an injector and convert it into water injector it's been currently producing for a few months. So that will be one of the operations we perform shortly. We are drilling, we're drilling right through the downturn here in Alaska where it really makes sense to do so.

The really important aspect of Alaska is the fact we've substantially increased the resource potential to 120 million to 150 million BOE. It was about 70 million to 90 million. 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 recent 3D shoots. And so this gives us a lot of anticipation for the future on Alaska, looking at that kind of resource potential. Today we've only booked 10 million-barrels in Alaska to give you 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've 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, of course, production but at the same time reducing cost, because we no longer have the stable oil FPSO in 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 Fourth Quarter production of about 8,000 barrels a day, up substantially, of course, from Fourth Quarter as we were growing throughout the year, and in addition to which our current growth production in that area is about 34,000 BOE per day. We have interest, of course, in various blocks that 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 3D and until, essentially in this case, oil pricing improves to justify drilling. We continue to work on our feed study which would 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 a project as we get into the early part of the next decade.

Finally in terms of my slide, Slide 21, I mentioned at the offset we've 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 to give you a few examples as shown on Slide 21. We already believe we've gotten about a 15% to 20% reduction in the well costs, that's as of the end of the year, and we're targeting another 10% to 20% reduction. We're trying to be thoughtful here in terms of utilizing our own Company owned facilities. In fact, we have a frac fleet we've moved from Raton to Spraberry so we're not using any outside parties now, we're using all internal equipment in the work we're doing so as to save costs. Just another example, this is just one example, but we're very focused on the details here. An example may be designing our own cement slurries to cut cost in our Raton operation, so we're very focused on this, in addition to which we're heavily focused on reducing LOE per BOE.

Of course, we want to work on the denominator to some extent, to,o so we're focused on production from current wells. To give you an idea, we have a selected 1650 well grouping that we've increased production over the last 12 months, some 7% to 9%, so we're very focused on the details of the nuts and bolts of current production, especially during this downturn. We're going to be the beneficiary of having renegotiated some of our electricity contracts, very substantial savings there.

We're really going to be focused on all of the details of production and where are those costs that run up to the last couple years ,including water hauling due to costs of fuel and so on, and we're really just focused,as I said,on every aspect of optimization in this field, whether it's compression or root optimization or reducing water production, what have you, 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

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, I'll kind of briefly go through each one of those. The gain on bond repurchase, we did buy $107 million at face value of bonds during the quarter and recognized a $23 million gain in interest and other income with respect to that on a pre-tax basis. As we 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 and other expense. I'll talk more about the ongoing effect of that in 2009 when I get back to guidance.

Acreage abandonments, we have some acreage that we did write-off that we're 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 a $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 these are hedges that we put on in December and prices were a little bit higher at year-end so we had a mark-to-market charge related to that. Obviously, they are in the 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 the increase to final cost to 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're at the high end of production so the assets continue to perform very, very well. Production cuts, I've got another slide on that, but we're at the high 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 the guidance range, and primarily related to the acreage charges I talked about earlier and seismic activity we were 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 when we were sitting in November, so that caused the negative price revisions that we've talked about and caused our DD&A rate to be a little bit higher.

G&A was inside the range at $38 million, interest expense, same, $40 million, rig termination and stack expense at $35 million, slightly below the range, mainly just because we were able to not terminate some of the rigs we thought we might terminate and stacked 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, commodity prices fell dramatically in the Fourth Quarter. Oil prices, our realized prices were down 32% relative to the Third Quarter on oil, 50% on NGLs and 22% on gas. Gas kind of had the double impact that we projected when we talked about our earnings for the Fourth Quarter in our Third Quarter call, where not only do we have lower gas prices but significantly wider differentials and for the Fourth Quarter differentials were 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 in the Fourth Quarter, were down 26% from the third quarter and, as mentioned previously, it's really reflective of the lower commodity prices and higher basis differentials on gas that drove the decrease. Obviously, production was up and the assets continued to deliver, it's 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 in 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 bar there, the base LOE, you can see we did see a cost reduction relative to the Fourth Quarter, so probably the turning point in terms of our cost reduction initiatives just getting under way. And I think probably to a larger extent, lower energy related costs 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 contracts in a 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 process goes down as well, and so we had a net $0.96 expense for the quarter related to net gas processing activities. I think the key point here is as Tim mentioned and went through in detail ,is that we do expect future production costs to benefit from our cost reduction initiatives and will 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 probably more important is what we're forecasting by quarter for 2009. As Tim and Scott both talked about, we have entered the year with nine rigs, 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 past mid February, our activity is going to be focused on Alaska and Spraberry and that will be the two areas 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 there we did update the new face value of each of the bonds reflecting the recent repurchases that we did in the fourth quarter. We did exit the year at net debt of $2.9 billion as Scott mentioned debt to book capitalization of 45%, down from 48% a year ago. And we are 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, so that's something we'll be focusing on with the free cash flow model that obviously helps that.

Turning to Slide 28, talking about First Quarter guidance. Production expected to be 117,000 to 122,000 per BOEs per day, in the First Quarter. Production costs 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, a reflection of the reduced drilling activity that we've got 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. Most of those rigs come off those contracts in mid year and so we'll see Second Quarter at a little lower rate, and then a substantially lower rate in the third and Fourth Quarter. Cash taxes expected to be $5 million to $10 million mainly, once again, just Tunisia is 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 would like to go ahead and open up the call for questions.

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

Good morning, gentlemen. I'd like to kick it off with a few questions on the Spraberry Trend area, and then a high level question.

You're seeing better economics in the Wolfberry, you've got pretty exciting results from what looks to be the strong. And when we met back in September we discussed the potential of numerous producing zones per well and the ultimate development plan. When you think about your revised plan with two remaining rig, how do you expect to drill and complete future wells?

Obviously, we're in a $35 to $45 oil price environment,and anybody that's drilling today, you know, the new volumes coming out obviously are not hedged, even though we're heavily hedged at $52 for this year. It's economical in the Wolfberry.,but any new volumes. The only reason we're running two rigs is really just to protect we have some large leases in the Wolfberry that we cannot get extensions on so it's economical. Long term, I'm confident that crude is going to get back somewhere between $60 and $80 over the next 12 months.

I'm confident that our well costs will come down similar to between $700,000 to $900,000 in a ,say, a lower price environment and we'll be back to somewhere between 8 to 12 rigs by early 2010. So the program will just restart back up. Most of our acreage locations is held by production and it's what's nice you can shut off the switch, invest capital wisely, why sell volumes at $40, $44 and let's sell them next year at $60, $65, $70. That's the game plan.

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 million today, and if we think about 40,000 to 50,000 per stage, what incremental recoveries do you expect if you add an additional, let's say, six to eight different zones?

Well, our Wolfberry slides are in there. They are 120,000 to 150,000 barrels per well and that's somewhere between a six stage and a 10 stage frac. All we're doing now is opening up a couple new shale zones, that's what Tim talked about and they are making about 20-barrels a day. And so that's generally about 40%, a third to 40% of the total well production. So we're starting to open up all those zones in our 20-acre and 40-acre drilling that we've completed the Fourth Quarter so we'll see those results as we produce these wells out as we complete them First Quarter and Second Quarter, finish up last year's activity. So we do expect, as Tim mentioned, to increase the resource, billion barrel resource based on those results.

Great. One last question on the Spraberry. You're seeing a lot more companies really test and explore acreage 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 acreage in the Wolfberry, but any insight as to what you're doing to test it and better crack the code would be useful.

We think that it's important, as we have seen in the Raton, to probably -- we will have a tendency to during this downturn to own more and more equipment in regard to pumping. We see the benefit of owning our own pumping services, we see the benefit of owning our own -- a lot of our frac equipment, frac tanks, pulling units, work over units. We've seen huge pay outs, one to two year pay outs, so we'll probably do more of that in the future.

Also, we'll 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 to the Wolfberry and some other areas, so we'll continue that. But we've done enough, we pretty much have defined a pretty good area where most of the better Wolf Camp wells are with the Spraberry Trend area. So we're also excited about upside potential in the Grayburg San Andres, and also in the Pennsylvania, as we see more and more prospects with our work.

Okay, one final question before I hop off. If we take a step back and try to get an understanding of how you look at 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 plowing capital into the ground and, maybe if you could give us an insight on how those discussions took place internally, that would be helpful.

Yes, obviously if you're trading at $4.75 per BOE when you got free cash flow, that's an excellent place to be putting your money, something that's probably worth the $12, $13, $14 range per BOE.

At the same time you got to improve financial flexibility but our debt got down to, some of our debt instruments got down to $0.60, $0.65 on the dollar, $0.68 on the dollar ,so that's a tremendous return, and so at $4 gas and $44 crude, I'm surprised there's really any rigs running in the U.S. Markets. So there'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 hedged, it's coming out of the ground, and so it's not very economical to be doing any drilling at this point in time.

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

Yes, I mean, going forward, we have such a unique asset base that we can essentially keep production flat if. we wanted to for three to four years, and basically buy in 100% of the shares and keep debt flat to 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 Raton, they have to exceed the value of our stock and we expect to get back to those type of returns in 2010. I think oil will reset significantly over the next nine months. Gas may be a little bit different story. The reason we mention BPP is simply because the strip is $6.50 to $8 over the next seven years, and also the differentials narrow by 50% in most all categories, so it allows us to look at taking advantage of that.

Okay, thank you very much.

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

Good morning guys.

Hi, Dave.

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.

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

Okay, and I guess the rationale 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 firepower 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?

Yes, our slide shows that if we do something on the slide, I think it's eight or nine 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 at the end of the day, we want to have improved financial flexibility and we want to have a lot less shares by the end of 2009.

Okay, and then diving into cost cutting measures and you discussed a G&A initiative. Can you give us 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.

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

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

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

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

We'll take our next question from Joe Allman with J.P. Morgan.

Yes, thank you . good morning

Hi, Joe.

Hi, Scott. Of the $69 million BOE of negative price related revisions, how many of those were PD and proved developed tails versus pud tails versus just pud eliminations?

Most of it was oil related, and most of it was due to the oil price and most of it was in the Spraberry and most of it was PDP.

Okay, great. Helpful. And then how about the positive reserve revisions, could you talk about those?

Yes. They were pretty much all areas. Spraberry, Alaska, Raton, Edwards.

Okay, very helpful.

Now one thing to note is since I had that talk with you about a year ago, I don't know if it was mentioned. But we do, our 20-acre drilling, that was put into the positive revisions. It did not go, since 20-acres is in field drilling inside of an existing field, we did book some 20's and that went into positive revisions.

Okay, that's helpful and how many 20-acre locations do you have booked at this point?

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

Okay. That's helpful. And then looking at the same kind of rate of return for the Wolfberry, if you just look at kind of more shallow Spraberry, if you're using 50 oil, six gas and 60 oil, the same price index you gave, what kind of rate of return do you see for the more shallow Spraberry?

The Wolfberry we're about 35% at 50 and 6, and the shallow Spraberry is going to be more like 20 to 22, 24 in that range.

Okay, that's helpful, and then--

There is return slides. Frank just mentioned in our slides in the back we didn't go over our return slides at various prices.

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

Yes, the Pennsylvanian, we aren't commenting due to the sensitive nature of it right now and we'll be offsetting this location toward the later part of the year.

Okay.

So we don't know how big it is at this point in time.

Okay, all right and then with the Pierre shale, for those two horizontals, what's the cost per well there?

Our goal is to get the costs down around $2.5 million per well and if we can deliver 3 Bcf, 2.5 Bcf or 3 Bcf or higher, it'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 we can get costs down to about $2.5 million on a horizontal well total.

And then the verticals, what are the costs there for the verticals and EURs there?

EURs, they are in the back of our slides, I think they are around $700 million to $750 million, 7.75 Bcf and cost around $900,000 to $950,000, and we think we can get them down even further from that.

Okay, and then lastly just the rig count you're still dropping some rigs, what's the rig count now, just onshore U.S.?

We're only dropping one more Spraberry rig so we'll be down to two, as Tim mentioned, and one Alaska. So three rigs.

Very helpful. Thank you very much.

We'll take our next question from Gill Yang with Citigroup.

Good morning, Scott.

Good morning.

Could you give any reasoning why the Ooguruk well, the 7,000 barrels per day, produced better than you'd expected?

Well, we didn't comment on it. When we brought on our first well it came on much better than expected. We wanted to watch it to make sure, and our second well came on 40% better than that well, so we decided,obviously with 3D seismic, to up the resource potential. We felt fairly good over the last six to nine months watching the start up of Ooguruk. We've seen the improvement of Alpine which is similar, Conoco Phillips and Anadarko. They've gone to frac jobs also.

There's two zones. And there's one zone that we'll be tracking later this year, so based on results at Alpine, we think that Ooguruk is going to be a lot bigger, two to three times the size than we initially came out with, so they're just getting much better permeability, much better porosity than we thought. So I'm glad our people were conservative going into it.

Okay, so it sounds like it's a combination of better reservoir and better tracking?

And also better, the 3D seismic, when we proved this we did not have 3D seismic. The Conoco Phillips had the only 3D 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 size of the field is bigger based on that 3D seismic.

Okay, all right for CapEx, you commented that you think you could keep production steady in 2010. Any sense for what CapEx level you would need in 2010 to do that?

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

For 2010?

2010 also, yes.

Okay, do you care to venture to 2011?

Well, I said I basically can buy in 100% of the stock over the next three to four years and keep production flat, barely flat, maybe a 2% decline in '011, '012, over the next four years, so there's not much drop off.

I'm under the impression that for 2009 and 2010, a lot of your growth is coming from Ooguruk and, I guess, Tunisia initially and South Coast Gas so sort of you're running up the momentum you built up over the last few years and so -- am I wrong about that because if I'm not wrong, then wouldn't your CapEx be--

One of the things that helps us in 2011 and 12 is that we have 13,000-barrels a day coming back on from our BPP's.

Okay.

So that's a big help in those years.

Okay. Combined for those two years right?

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

Right, right. And then finally, if you're using your own rig fleet, almost exclusively now, how are you going to squeeze another 10% to 20% out of costs?

No, we're using our own frac fleet.

Okay.

So it's only our frac fleet that we're using. Generally, if you own your own equipment in a downturn, what we're seeing is that the service companies are, I predict, over the next three to six months will get down to bare bones where they are losing money in regard to certain activities, so when you own your own fleet you don't make any money. It's really the up cycles where if you 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 rates of already somewhere between $8,000 and $10,000 a day for a thousand horsepower rig or less, and we're paying roughly $12,000 to $15,000 on these last two rigs.

So 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, it's already built in. It's 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.

Okay. All right, thanks for that, Scott.

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

Thank you, good morning.

Hi, Brian.

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

Yes, I'm surprised by the comments that I've 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've seen any new leases, you cannot drill a well and leave it shut in. You'll lose your lease, and so it's got to be on held by production leases that people are doing that. So I don't understand the companies that are doing that, and you really have to ask them.

Okay. And then I guess the flip side is when you do start drilling again if commodity prices improve, wouldn't you expect an immediate production ramp or is there some delay that we should expect?

It will be a lag period of about at least three months. Obviously in South Texas, with the type of 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.

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 are there different numbers for those three basins?

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

And it would otherwise be a higher gas price today, but with your expectations for falling well costs you think that can get it down to 6?

Exactly, and also improved differentials. The differentials have widened out. You can see, we didn't talk about them but we have hedged at least half the differentials. The differentials blew out again the last two weeks, in regard to Permian, Barnett Shale, mid-continent, Rockies and so trying to prevent that blowout is basically we've already hedged half the differentials this year. We're hedging aggressively over the next two or three years differentials.

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

No.

Thank you much.

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

Hi, good morning, guys. Just looking for a little bit more data on your Alaskan oil wells, that recent well that you guys brought on at 7,000 barrels a day, how long has that been on production and what kind of declines are you seeing on some of those older wells over there?

Well, it's simple. We've seen zero decline in the well just tested last week. So, don't have any history yet, but obviously, Tim talked about the injection. What's important when you're 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. But the first well we've seen essentially no decline for several months, first set of wells.

Okay. Jumping over to the Spraberry, obviously you guys have been testing some of inter bedded silt stones there and the shale formation with some pretty good results. Just to make sure I understood some of your earlier comments, are you guys basically co-mingling those with some of the traditional Spraberry sand zones and looking to have some results in the next four or five months, is that what you were saying earlier?

Yes, exactly. And yes on the first question.

Okay.

Yes, you're allowed to co-mingle all zones. You can co-mingle in the Spraberry from Clear Fork all the way down to the Wolf Camp. And you can do the Pan now, is it approved?

Okay, a question with respect to your production guidance in 2009. You talked about having flat production with relatively limited CapEx. When you guys say flat production, is that flat to your First Quarter guidance of that 117 to 122 number throughout the rest of the year, just trying to make sure I understood your comment there.

No, it's calendar year to calendar year.

Okay. Thanks a lot,guys.

We'll take our next question from Ray Deacon with Pritchard Capital.

Yeah, hi. A question for Tim. I guess, did you combine the new hedges that you did with basis hedges, and can you just remind me how -- I know you tend to get a better than Rockies price in the Raton. Where would you expect to be able to lock that in for the next year or so?

Yes, as Scott mentioned, half of the gas hedges we have locked into differentials favorably compare, especially compared to history. We have over time, as you know in the sense of Raton assets, priced the gas there in mid-continent markets. Mid-continent markets didn't have a very good run at the end of 2008 and have blown out a little bit since then, but my recollection is our current hedge position vis-a-vis the mid-continent is about $1.20 on average, is that right, Rich?

For '09. And $7.90 for 2010.

Got it, great. Thanks very much, and in the budget that you've adopted for '09, will you be going back into drill additional horizontals in the Pierre or is that 2010?

Well, today, we're sort of evaluating, as I mentioned in my comments, what the next direction vis-a-vis this whole fracture patterns, the fracture orientation, so we got a little science work to do. So I would anticipate to the extent we drill, it will be later in the year, perhaps it will eke into 2010.

Okay, got it. So you're doing microseismic?

Right. Microseismic is going to take quite a long time to get done.

Got it. Thanks very much.

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

It's actually Xin Liu for Joe Allman. On your reserve, you have some positive technical revisions. Can you give us an idea what percentage is from in field revision?

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

Okay, thanks.

It appears we have no further questions at this time. Mr. Hopkins, I'd like to turn the conference back over to you and the presenters for any additional or closing remarks.

Okay, well again, we appreciate, obviously, hopefully everybody has seen that we have a great set of assets, we're monitoring through this downturn, we're 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, reducing shares and reducing costs is the current focus, preserving the value for the shareholders. So again, thanks, we look forward to you in the next earnings

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