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Pioneer Natural Resources (NYSE:PXD)

Q3 2008 Earnings Call Transcript

November 5, 2008, 12:00 pm ET

Executives

Frank Hopkins – VP of IR

Scott Sheffield – Chairman and CEO

Tim Dove – President and COO

Rich Dealy – EVP and CFO

Analysts

David Kistler – Simmons & Co.

Michael Jacobs – Tudor, Pickering, Holt & Co.

Gil Yang – Citi

Joe Allman – JP Morgan

Leo Mariani – RBC Capital

Rehan Rashid – FBR Capital Markets

Monroe Helm – CM Energy Partners

Operator

Welcome to Pioneer Natural Resources’ third quarter conference call. Today’s call is being recorded.

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 relating to today’s call is www.pxd.com. At the Web site, select ‘Investors’ then select ‘Investor Presentations’.

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

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

Frank Hopkins

Good day, everyone, and thank you for joining us. Let me review the agenda for today’s call to get things started. Scott is going to be the first speaker. He will go over the financial and operating results for the third quarter of 2008. He is then going to highlight Pioneer’s current strong financial position and the initiatives that we have recently implemented to maintain financial flexibility and improve returns in response to the recent economic downturn and commodity price collapse.

After Scott concludes his remarks, Tim will review the performance of our key assets during the third quarter, and expectations for the remainder of year. Rich will then cover the financial highlights from the third quarter, and provide earnings guidance for the fourth quarter. After that, we will open up the call for your questions.

With that I’ll turn the call over to Scott.

Scott Sheffield

Thanks, Frank. Good morning. We will start on Slide number 3, third quarter financial results. Pioneer reported net loss of $0.03 a share that was primarily impacted by the two hurricanes where we lost about 3,000 barrels of oil equivalents per day in both the Permian Basin in the Spraberry field, and in South Texas. We had widening differentials relative to NYMEX gas prices. In fact, we’re seeing it even get worse as we go into October and November. Just to remind everybody, 80% of our gas to 85% of our gas domestic is located in the Mid-Continent, Permian and Barnett. In the Raton, we tied a Mid-Continent pricing. So, we had 80% of our gas today is getting about $2.80. The differentials have widened and have extended and gotten wider in October and November. In addition, we sold most of our Tunisia and South Africa oil at the end of the quarter at much lower quarter-end prices than estimates by analysts.

We had significant non-cash charges. We had a Uinta Piceance impairment due to low gas price and wide differentials in our assets there. We eliminated ongoing operating and carrying costs of our Lay Creek CBM project that we started up in 2006 and also our Delaware Shale project in 2007. Obviously, in low gas prices, these type of investments are not worth going forward. And we did announce awhile back our SemCrude potential allowance. We went ahead and took an allowance for SemCrude in regard to what we feel like we’ll get paid.

Adjusting all these items, non-cash charges, we had earnings adjusted for unusual items of about $0.91 per share. We continue to reduce shares as we have over the last two to three years by another 2 million shares in third quarter, then also in October. And we think it’s important to immediately deliver a free cash flow model going forward.

Slide number 4, operational highlights for the quarter. We started this over a year ago, but we did receive approval by the Railroad Commission of Texas to down space 20-acre downspacing. That will give us about 500 million barrels putting into the probable category, which allow us to achieve very low finding cost over the next several years as we continue to develop the Spraberry field over the time frame. It was unopposed, had total support from all the operators of the field. So, highly encouraged by that action. In addition, continuing and Tim will update you – we have had great results from our 20-acre drilling, still very similar to 40-acre drilling. And also with an encouraging core analysis and shale interval testing, we are seeing more upside to the numbers that we’ve given out on both 20-acre and 40-acre spacing as we open up more pay zones.

Continued to increase our Wolfberry Trend acreage of about 30,000 acres in the play. This is an area where several of our wells are making 100 barrels a day or greater. And that is where our remaining 7 rigs will be focused on primarily. First two Pierre Shale horizontal wells encountered very intense natural fracturing and gas shows much better than we thought. Tim will update you on the activity there. In addition, we’ve been working in the Eagle Ford for over a year. We were surprised and encouraged by Petrohawk’s announcement of a 9 million a day well. We began drilling our first well about two weeks. It’s in the horizontal stage now. Obviously, we were going to wait like we talked about the Pierre, we’re going to wait and produce the well for six to 12 months, before we’ll drill two wells, produce them before we let the market know. So, I will be excited about Petrohawk’s discovery. And we are highly encouraged by what we see through all the wells that we’ve drilled, average wells through the Eagle Ford in that play. We also had two Tunisian discoveries, one more Edwards discovery and finally our most prolific South Coast Gas project gas well came on production.

Slide number 5, after several meetings over the last several weeks, the management in looking back at history – we decided to be very prudent in this low price environment. We saw crude touch $61; just recently we saw gas touch $6.20. Obviously, the markets in Contango, which I am still not highly encouraged in regard to prices immediately getting back to $80, $80 and $8, or some price even above that. We could easily move forward with these low prices as we have seen in past downturns, the market stays in Contango and moves forward. Generally, people continue to drill through these cycles. They overstrain cash flow, history has shown most companies in that delivering poor economics is probably generally the worst time to drill when you are drilling at the top of the market. With service costs, you are getting lower commodity prices.

We decided to take a different approach. And that approach is significantly reducing the rig count, significantly improve our strong financial flexibility, and essentially it is better to be buying stock at $5 to $6 a BOE, reducing debt, and restart the growth profile in about six to 12 months. We think it generally takes about six to 12 months to see costs come down. We are already starting to see some costs come down, but it generally takes, in meetings that we’ve had over the last several weeks with service companies, it’s going to take a good six months, maybe up to 12 months. We want to maintain strong financial flexibility. We have no significant bond maturities until 2013. We have $775 million of liquidity. Our average interest rate on our debt is about 5.5%. Through the first nine months, our capital spending in line with cash flow for 2008. With this recent cutback, we will see in December, CapEx is expected to be obviously less than $1.3 billion, somewhere between $1.2 billion and $1.3 billion for the year. We have hedged 20% of our oil production with $100 floors and $190 collars in 2009, 2010. We also have legacy hedge and VPP expirations providing significant cash flow in 2009 and beyond, there is a chart, back in the appendix that talks about that.

We feel like that we need to operate as if we are in a $60 oil, and $6 gas environment. It may last for several months. About doing that, obviously we want to minimize drilling activity until we get the service cost down, gas differentials have to improve significantly. As I mentioned, 85% of our areas, today we are getting $2.80, Permian Basin, Barnett, Mid-Continent, and the Raton. So, we need both gas differentials to improve significantly and well cost to improve to return back to the returns, which we will talk about, that we show.

Reducing 60% of our rig activity until costs approach 2006 levels, we are targeting 20% to 30% cost reductions. We have already seen about 10% to 15% in certain of our key areas. In addition, reducing well service units, primarily in the Spraberry Trend area field from 42 to 30, which will obviously have significantly lower operating costs. We have 15 remaining units and we will continue to buy more units over time to help drive the costs down, because we can operate the service units much cheaper than we can by renting from third parties. We also think it is important to deliver free cash flow and not continue to have a strong production profile and overspend cash flow and take the risk that commodity prices will bail us out in this marketplace.

We expect – what is unique about our asset base is the fact we can have a 60% cut back, and still grow 5% to 10% production growth in 2009 with a significant reduced capital budget. If for some reason we see lower oil and gas prices, much lower than $60 and $6 for two years, we can actually cut back to $200 million per year and actually keep production flat in 2009 and 2010, which lends itself to our attractiveness of our low risk drilling inventory, low decline rate, and low decline assets.

So starting out, our CapEx is around $500 million. Obviously it will increase over time as we see these things improve. But we are starting the year with about a $500 million CapEx with our current reduction in activity.

Turning to slide number 6, gives you an illustration of returns of our key asset, the Spraberry, which is about half the company. All of our assets have had very similar returns during 2005 through current. The exceptions will be Tunisia, which still had the best returns in the company, and Alaska, which has great returns, but primarily due to costs forward. This is primarily Raton, Edwards, Barnett and Spraberry Trend areas, but we use Spraberry as an example. You can see what happened in regard to the returns, we have generally been getting historically about a 40% return over the last several years, which is great return.

We saw a significant rise in service costs. Service costs have doubled in a typical Spraberry well from 2005 to $1.4 million. And all of a sudden we're back to the same price that we showed an average $57 in 2005 or $66 in 2006. We feel like we need to get our Spraberry costs down to about $1 million. With the rigs we have running, we have gotten our costs down already 10% to 15%. Certain drilling contractors, which we won't mention names, have been very easy to negotiate with, very accommodating, and certain ones haven’t. Obviously, as we see rig contracts expire, we will begin – costs come down, margins improve, we will get back to 17 to 20 rigs by the end of 2009, sometime in 2010. Obviously, these are all before tax returns and we need at least 35% to 40% to put all of our rigs back to work and we are confident it will happen. It is just not going to happen overnight as we have seen commodity prices decline.

Slide number 7, this gives you a little bit of a rundown on some of our negotiations and what has happened in the rig count area. Again, this is primarily done because we feel like that costs will come down significantly. So we are taking a termination charge of about $40 million to $45 million, which really reflects about $500 million of expenditures. We feel like it is a small charge to take to make sure we do not overspend and drill wells at a 20% return and sort of wait and hope for costs to come down. So, we think it is important to take this charge, shut the rig count down, develop free cash flow immediately, gives you the flexibility to buy stock cheap, also improve your financial flexibility by buying debt cheap, waiting for costs to come down, which again, I said will take about six months. So you can see the rundown that we show.

We have seen some improvement significantly from some drilling contractors. Steel, we see moving down significantly in talking to some of the world's largest steel distributors. And again, pumping services, pretty much due to the backlog of pumping services that we see in the onshore US, we see that one will take more time before it reflects coming down. We are looking at bringing down some of our frac crews down from Raton to help get on costs down immediately. In Spraberry, Trend area for instance, to form our own frac jobs down to $1 million.

Slide number 8, again shows the consistent performance of our asset base over the last several years. We will end up exiting the year about 16% to 17% production growth. Excluding hurricane impacts, we would have been at 18% to 19%. Going forward with our key asset base, with a 60% drop in CapEx, we are still growing somewhere between 5% and 10% in a very, very low commodity price environment for 2009. On a per-share base, we have averaged 17% we are estimating through to the end of 2008.

Slide number 9, really an update on some of our assets. Again, our assets performing at or above expectations. We have had strong production growth performance, 18% over the last 12 months, nine months of 2008 versus nine months of 2007, primarily driven by our core assets at 23%, Spraberry, Raton, Edwards, Tunisia and Alaska. We still expect 2008 F&D cost to be in a range of $15 to $20 per BOE. This does exclude price revisions. We do expect if the wide differentials go out through December 31 of this year, we do expect to lose somewhere between 10 million and 15 million barrels of long life gas reserves out 50 years to 60 years, which have a zero Pb effect.

In addition, we expect to lose somewhere between 10 million and 15 million barrels of Spraberry if crude is priced, for instance, at $60 to $65 at the end of the year. These are all tail reserves; wells that produce at about 60 years to 70 years have zero effect on a Pb basis.

We have over 20,000 drilling locations. We still have over 1.8 billion barrels of oil equivalent net resource potential. Even in a $60 and $6 environment with cost reductions, this number does not change. We have continued upside from new shale plays that we haven't [ph] booked, primarily the Pierre performance from the horizontal and also from KP2 and KP3, the Spraberry shale intervals, additional Barnett opportunities that we have picked up in acreage, and also the Eagle Ford is not our number also, which we’ll know results over the next several months.

To restore back to the 14% production per share growth target, we feel like we need to get to $80 oil and $8 gas, really a sustained environment that we are confident in. I feel like we will get back there, within six months, a year or two years, we don't know, but we will be back there and company will be growing again strong at that point in time.

In 2009, it is more important to deliver free cash flow in 2009. Be very prudent with your capital, continue to reduce shares, reduce debt, we have had several opportunities to purchase debt significantly below carrying value and looking at any bolt-on acquisitions.

Let me stop there and turn it over to Tim to update you on each of our key assets.

Tim Dove

Thanks, Scott, and I will start by doing so by turning to slide 10. Spraberry assets continue to perform exceedingly well. In fact, we increased production in the third quarter of 2008 some 10% compared to the prior year quarter; and that was even considering the fact we had such curtailments and shut-ins due to the hurricanes and their affect on third-party fractionation facilities in Mont Belvieu in addition to the scheduled turnarounds in those facilities. In fact, we lost about 7,000 barrels a day on average in a drop between August to September for the same reasons; meaning that overall, the quarter was curtailed some 2,500 barrels a day BOE basis on average. We continue to see the effects of the hurricane as we are now in the process finally between now and mid-November next week probably getting all these wells back on stream and then getting back to our normal position we would have been in lieu of the hurricane some 33,000 BOE per day.

We have about a 15% growth target now for ‘08, that would have been, as you know, over 18% had we not been affected by the hurricanes. But suffice it to say, the assets are performing exceedingly well, and will continue to do so. As Scott has already alluded to the rig count cut, that will have the effect of dropping down the total wells drilled during the fourth quarter and you have the numbers on slide 10. The curtailment, I think is a prudent thing to do in terms of capital allocation, until we really see where price and costs land in today's volatile market and when margins improve we will be raising those rigs. And the fact is, we are the dominant driller, we are the largest player, we think we can affect cost decreases pretty rapidly by taking these actions, and the whole objective is of course to return to a more normal set of return metrics looking ahead.

And in slide 11, we are confident in saying that even with all the market turmoil we have seen, that we continue to have our eye on the ball in terms of unlocking the enormous resource potential of the Spraberry, Trend area, and certainly none of that has changed in lieu of the current situation in terms of the economics in the world. That is to say, we are continuing with our 40-acre field development, where we have some 200 million barrels BOE basis unbooked. Scott already alluded to the fact that the Railroad Commission of Texas approved the field rule change. We are still in the process of drilling our 20-acre campaign for this year; we have a total of 23 wells planned. In fact, we have already drilled nine of those and continue to see where the positive results. We are seeing these wells come on typically in the neighborhood of 40 barrels a day to 50 barrels a day, which is very similar to their offsetting 40 locations, and that gives us a lot of confidence that the IRRs on these 20-acre wells very similar to those of 40-acre wells. And the potential is significant, in the sense that we have about 500 million barrels unbooked in the 20-acre campaign.

Water flooding project continues. We have done about 6,000-acre area, under one of our existing units that will be progressing the water flood for 2009, including drilling several injection wells and converting some current producers to injectors. And then in addition to which, we will be needing to add more wells in terms of 40-acre drilling producers as well. So overall, that project is looking good and we are proceeding with that with all due haste as a 2009 project. The overall objective of course, in the longer term sense is unchanged. That is, in those sections where applicable, getting the recovery rates up to 27% to 28%, where they will be only 12% to 13% on those same sections based on traditional 40-acre field development.

We are getting a lot of positive results on our shale/silt non-traditional intervals in the Spraberry as well. You recall the one where we took 650 feet in core. Further review shows we think we have added on a net basis about 30 feet of additional pay. We are in the process, of course by testing these wells of evaluating how much contribution of resource potential that can give us. Too early to state that, but nonetheless we think that these non-traditional intervals will in fact add EUR to the wells. And we are making still about 50 barrels a day by testing only the non-traditional zones in the silt/shale interval and we will be testing two more wells as we – actually we’ll be testing two more zones in this one well, one other non-traditional zone and a more traditional zone, and looking at the overall contributions of each before we go through next well.

Horizontally speaking, we have now completed four re-entries, continue to see the same sort of benefits from horizontal drilling, at least where applicable that is, about a sixfold increase in production after stimulating the well. We are on our last of five that we have planned for this year, and at this time, we are cleaning out the lateral section to begin the completion process. We will have to evaluate the next year whether to do any more horizontal activity. We are considering potentially a grass roots horizontal well next year, and that of course will depend upon what we think about commodity prices at that time.

Turning to slide 12, Raton has really been a solid producer this year, in the sense production is up about 12% versus 2007’s third quarter. And we are making a lot of progress, both with regard to completing our coal-bed methane drilling as well as our Pierre shale program. The vertical shale performance that we have seen in some newly drilled wells that have been put on production continued to show that the vertical Pierre shale program in KP1 only and now additionally adding some KP2 and KP3 zones have excellent results. And in fact, we have seen results that indicate to us that again, we are probably adding in the neighborhood of 20% to 30% in terms of additional contribution, by coming uphole and completing the wells in the KP2 and KP3 as well.

Importantly, I had hoped to have results for you for the results of the two horizontal shale wells we are drilling in the Pierre. And at this call, these fracs are taking some time, we are making very good progress, we already have three stages fraced in our first horizontal well, we have two remaining stages, probably will be done in the next couple of weeks. The results look very, very good in the early stages. Our image logs, that we have run down hole show very significant fracturing in both of the 2,000 foot laterals we have drilled and so that gives us a great deal of encouragement. Of course, we are then going to move on and prepare to frac the second well. But suffice to say, we do not yet have any results, but overall, from the standpoint of what we have seen from the technical standpoint, we are encouraged. We are going to be reducing our drilling along the lines of, what Scott has mentioned, in this area owing to the fact that gas differentials are extremely high, that is to say, our net (inaudible) low based on this gas being tied into Mid-Continent pricing. And we will look at a 2009 program that is currently curtailed but we will be evaluating the potential for improvement in margins and particularly in light of how we evaluate what happens with horizontal Pierre results; that will dictate the amount of spending for 2009.

On Edwards Trend on slide 13, excellent results. As you recall, we have ended the year with about 25% annual growth rate target. Now we still continue to believe we are going to do over 40%. In fact, our current production is now over 80 million cubic feet a day as we put in one of our three aiming and training facilities and have two more to add during December. And accordingly, we feel pretty comfortable we will be able to tie in the 10 million cubic feet a day or so on a net basis that is currently shut and waiting for that treatment.

We did make a new discovery in the trend. It is at 25 Bcf plus or minus resource potential area that of significance fills in a gap between two recently discovered fields. We are going to be introducing the rig count here from 6 to 2, and accordingly, we drilled a few less wells in 2008. It is again in relation to what is happening with the gas differentials. We will be evaluating 2009, as I mentioned, in relation to Raton in the same vein, that is the margins improve, the economics are strong. We are completing our large seismic shoot. It is a 900 square mile shoot. We're about 90% shot on that and interpretation is ongoing. It is opening our eyes to fault patterns and Edwards structure, which are important in terms of looking at where to complete the wells and in what configuration, just details on the prospects that we simply couldn't see on 2-D alone. So we are very pleased what we are seeing there in terms of the Edwards 3-D shoot.

Speaking of Edwards, we are really speaking of South Texas. We have another slide in here that Scott alluded to. Our interests in the Eagle Ford shale and that shown on slide 14. I thought it would make sense to discuss our interest in the Eagle Ford shale, we really have never discussed this before, but in light of the Petrohawk discovery it seems to make sense. We have about 15,000 acres it turns out just north of the Petrohawk discovery, which is in La Salle County, as shown on the slide. But really, the play is a lot more extensive than that and really underlies all of our other Edwards related acreage as you go northeast from their discovery through the entire trend. And of course, we have a lot of data on the trend. We have, of course, 150 wells or so in our 310,000 acre lease position that you can see in the yellow boxes in the slide. This whole acreage of course is spread over the whole Edwards trend, which is six counties and about 150 miles long, and just a few miles wide along the Edwards reef trend. And every one of our wells of course is drilled through the Eagle Ford, because the Eagle Ford directly lies over the Edwards that we're drilling the reef play. And it is the case that as we drill through here, it is frequent that we have to actually flare gas when we are drilling through the Eagle Ford and we have logged all this information in all of our wells.

It gives us a lot of encouragement that we have Eagle Ford ubiquitously spread across essentially all of our Edwards acreage. And we know that the Eagle Ford has significant unconventional gas potential across the acreage. We have been gathering the data to be able to progress that, to map it, and to quantify what we think is the potential. And what we believe is, if the Eagle Ford is present across all of our acreage, or at least 100,000 acres we control of that acreage, and based on the sweet spot we think we have identified, it is probably about 30,000 acres that we are going to choose to drill our first initial wells. And the first of which we spud in Dewitt County in the middle part of October. It is about 100 miles north east of Petrohawk’s discovery and the objective is it begins the test the Eagle Ford on our acreage. We have just completed coring this well and are preparing to drill a lateral section and we should be done with that well, say in the next couple of months. We will be drilling the 2,500 foot lateral and be using the typical multistage isolation packer technology. Then we will drill our second well about 5 miles away. So as we get into the latter parts of 2009 or in the middle parts of 2009, we can talk a little bit more about how these wells are performing in the early stages of evaluating what our potential is. But we think looking at early economy and early evaluations that our current estimate of mean recoverable resource potential within that sweet spot is already over 500 Bcfe. The cost of the wells in the Eagle Ford wells would be essentially similar to the Edwards wells we have drilled. They are basically the same depth and will have similar costs. And of course, by the time we get through with all of our infrastructure development, we will have the ability to tie in to some of the Edwards infrastructure we have been waiting on and putting in place for the last couple of years.

We also believe we have Austin Chalk potential that sits immediately above the Eagle Ford shale, and it could be substantial in terms of resource potential, because we believe it to be also gas charged as it overlies the Edwards reef structure and that is frequently fractured. We have also typically got a flare gas when drilling through that Austin Chalk zone, which is typically about 300 feet in our areas. So we know we have some conventional pay within the Austin Chalk that is currently behind 5 and we are really also in the process of looking at the resource potential and seeing where there are attempts to test the Austin Chalk in ‘09. So that is just kind of a recap of a new thing we are looking at and we are pretty excited about it. It turns out that we have the acreage in place that we believe can lead to substantial growth in a new play.

Slight 15 is Tunisia. We have drilled a couple of discovery wells in the third quarter there. One of importance is in the Anaguid block, you see it on slight 15 in the light blue color, it is some 940,000 acres. We have drilled the first wells testing that technique, which has worked so well in Cherouq over the last few years, testing the coccus and a tested well here at 2,300 barrels of oil equivalent per day; it is about half gas and about half liquids. And we will continue to evaluate next steps as a result of that discovery. And also in the second well that we drilled, there was a discovery in Cherouq, we are testing it as well. Overall, in the Cherouq concession, which is our major producing operating concession, we have had about 70% success. Turns out, 2007 we were essentially 7% in terms of drilling new blocks and new opportunities from the spot prospectivity case.

Overall, success has come down in 2008. In fact, this year, we have drilled about 2 out of 6 successful wells and of course, a couple of those we’re testing in other zones such as the TAGI and the Ordovician that is a deeper formation. But with the success rate falling somewhat in 2008, it has affected our growth rate. So we now look at our potential growth rate this year in growing to more like 50% to 60% and our exit rate this year would be affected by this as we go into 2009. We are still producing about 7,500 barrels of oil equivalent a day from our three producing areas on a net basis. We continue to also evaluate drilling to find more gas, potentially in our southern acreage in that industry players along with ourselves are embarking upon a field study to potentially in the future move gas from the southern gas productive areas to northern gas markets. Still continuing to evaluate that as a part of that consortium.

In slide 16, South Africa, of course, we have made the major change now. We have produced about 3,800 BOE in the third quarter, but importantly, we have now changed the – what had been an injection well in the Sable oil project to a gas producer in the South Coast Gas Project. It is our largest and most prolific well and we now have got that turnaround into a gas producer, and we have actually turned it around earlier than we thought, ahead of schedule. And importantly, we are seeing very good rates, very good performance, we are ramping this up as we speak, currently about 70,000 million cubic feet equivalent per day. We will be taking that to 80,000 to 90,000 early next year and this is just simply producing the wells on a gradual basis of increase without any costs needed to speak off. And therefore, we can look at pretty substantial growth in production both this quarter and getting into 2009 as shown, increasing to some 30 million to 35 million cubic feet a day equivalent next year.

And very importantly, in terms of the margin out here, we of course will be very soon releasing the Glass Tower, that was the vessel that is processing Sable oil. Of course, with the production having come down, the fixed rates haven't been so significant, that will – by it’s being released will have a substantial reduction LOE down from some $30 a BOE to less than $5. So margins should be improving dramatically in South Africa, notwithstanding increases in production.

Alaska is really doing well. Of course, in the third quarter, we were affected by the longer than expected turnaround at a third-party facility that processes our oil onshore, but that is now back on stream and we have already reached our exit rate on that basis of about 3,000 barrels a day. We will be continuing to drill of course in 2009 and 2010 and you see here on slide 17 the rates, probably about 5,000 barrels a day net in 2009. Big increases we get in 2011 as development continues to grow with drilling wells.

At Cosmopolitan, we are still in the process of permitting and – the process of our feed studies or our early engineering studies for the facilities that would take to develop the offshore discovery, in light of the current uncertainties on oil prices, we most likely will defer the drilling of the well that we had planned for 2009 into the following year.

And with that, I think I will pass it on to Rich for a review of the third quarter financials.

Rich Dealy

All right. Thanks Tim. Starting on slide 18 for the quarter we did, as Scott mentioned, we did report a net loss of $3 million or $0.03 per share. Scott went through the unusual items that were impacted in the quarter. Those totaled about $0.94 you can see on slide 18. So, adjusting for those items, income was $0.91. Obviously this is before taking into account the differential impact that Scott mentioned and that are continuing into the fourth quarter.

Looking at the bottom of the slide, production for the quarter was 112,000 BOEs per day, at the low end of our adjusted guidance that we put out in September, mainly because it took a little longer to resume some of the production than we originally anticipated. Production costs I have a slide on here later, but mainly, the impact there relates to the hurricane effect of having some fixed costs and higher energy related costs that I will talk about in a little more detail in a later slide.

Expiration and abandonments for the quarter, $111 million. This does include $60 million related to the Lake Creek CBM and Delaware sale abandonment that Scott mentioned. Had those not been in there, we would have been towards the bottom end of the range of about $51 million in expiration and abandonments. DD&A for the quarter $12.39, above our guidance coming into it. Once again, this is impacted by negative price revisions that occurred at the end of the third quarter as a result of the widening differentials on gas and lower gas prices and losing some tail reserves associated with those activities, therefore increasing our DD&A rate. G&A, interest expense, minority interest, cash taxes, all generally where we would have expected those to come in. The effective tax rate really is just a result of having a small net loss combined with having a higher effective tax rate in Tunisia, where we generated earnings during the quarter, offset by a lower tax rate in the US, where we had a loss for the quarter as a result of these unusual charges.

Turning to slide 19, a look at price realizations. On oil, and the green bars, where you can see oil price realizations for the third quarter were down 9% from the second quarter. As Scott mentioned, this was primarily due to the timing of liftings coming out of Tunisia and South Africa, where they were at the back end of the quarter where oil prices had fallen towards the end of the quarter resulting in a wider differential when you compare that to average prices for the quarter. Also impacting the Q3 was a legacy hedge as you can see at the bottom, underneath the Q3 column there that we had $41 of negative impact related to hedges, most of that’s attributable to our legacy hedges that we have talked about. And the nice thing, it will end and go away at the end of this year.

Looking at NGLs, NGLs for the quarter were at the 11% compared to the second quarter. Obviously, this has taken them longer to readjust as they moved into the third quarter. I think the more important point is that, as Scott mentioned, in the fourth quarter, NGL prices are significantly down and NGL prices today are about $35 per barrel.

Looking at gas realizations, down 8% for the quarter. Clearly, as Scott mentioned earlier, widening differentials is the biggest story here and with 85% of our North American gas being impacted by this wider differentials we do expect to see a further decline in the fourth quarter, particularly as we are realizing about $2.80, as Scott mentioned, today. Now that doesn’t reflect the impact of our hedging, obviously we’ve got a slide in the Appendix that shows our hedging position. So, we do expect to benefit in the fourth quarter, both in NGL-wise and gas-wise from our hedging positions.

Turning to slide 20, production costs. Our production costs were up $1.20 relative to the second quarter at $15.13. Base LOEs were the primary contributor, that’s really focused on a number of items but the first being fixed costs associated with the hurricanes where we had curtailed production, but still incurred the cost and losing the BOEs impacted that, when you look at on a BOE rate. The other thing we had higher trucking fuel surcharges associated with our salt water disposal. So that is something that as we move into a lower price environment will be kind of non-recurring and come back to lower levels. We had a compressor maintenance and repairs in Raton. Areas that were above what we budgeted, we do run a budget on that but these were abnormal in the quarter. And then electricity costs also were higher in the third quarter, and once again we do expect those to come down as we move into the fourth quarter, and particular as we move into 2009, a lot of these energy related costs that impact production cost will be lower in today’s commodity price environment.

Turning to slide 21, fourth quarter guidance. Daily production expected to be 114,000 to 119,000 BOEs per day for the fourth quarter. That does take into account our estimation of losing about 2,000 BOEs per day associated with the hurricanes and the maintenance in third party facilities not being back in place until next week, and being back at full capacity. Production costs expected to be $14 to $15, as I mentioned in our previous slide, down slightly from where we were in the third quarter, but really expect more cost savings as we move into 2009.

Exploration and abandonment, $40 million to $70 million, primarily associated with drilling that’s ongoing in Tunisia and the Edwards Trend. D&A is expected to be $13 to $14, once again up from where we were in the third quarter due to the price revisions that Scott mentioned that we anticipate to see it into the year end, our South Coast Gas project that Tim talked about having a higher depletion rate. G&A, interest expense, minority interest, all are normal run rate there, so nothing really to talk about. Scott talked about the termination charge and stacking charges associated with the rigs due to our lower cost initiative environment, and so those are $40 million to $45 million estimate. And categorically it could be $35 million for termination charges and $5 million to $10 million on stacking charges.

Cash taxes, $15 million to $20 million, all associated with Tunisia; and our effective tax rate is expected to be 40% to 50% for the quarter.

Turning to slide 22, and just to give you a brief picture of our liquidity situation. Net debt, $2.8 billion at the end of the quarter. Debt to book capitalization at 44%, down from 47%, 48% at year end ’07. Credit facility availability is at $775 million. So, plenty of capacity on our facility. I will also mention, we do our covenant calculations on a quarterly basis. We got plenty of capacity into our covenants. So, no issues on that front either.

Scott talked about our maturities, so our credit facility is good through 2012. No significant bond maturities until 2013. And I think on a longer term view, we still are targeting 35% to 40% debt to book capitalization and expect to be there in 2009.

Turning to slide 23, really just to point out that we have a number of supplemental slides in the back for your review. We are not going to cover those today, but want to point those out.

And so that really concludes my remarks. So, Pam will go ahead and open up the call for questions now.

Question-and-Answer Session

Operator

(Operator instructions) And our first question comes from David Kistler with Simmons & Company.

David Kistler – Simmons & Co.

Good morning, guys.

Scott Sheffield

Hi, Dave. Do you have a question, David?

Operator

Mr. Kistler, go ahead, your line is open.

David Kistler – Simmons & Co.

Can you hear me?

Scott Sheffield

We heard you then, we didn’t hear you before.

David Kistler – Simmons & Co.

I am so sorry. Quick question for you guys with respect to being able to maintain production guidance that’s kind of a 5% to 10% with the large CapEx cut, obviously high lives, low decline assets, can you breakdown what portion of that you expect to be oil, what portion you expect to be gas, and maybe associated declines at both of those?

Scott Sheffield

Yes, I think we have a slide in the back on the Appendix that goes overall the reasons why we can do that. But obviously we got South Africa that is growing. And you’ve got Alaska that’s growing. South Africa you've got to realize is tied to Brent pricing. So, it’s oil, even though we are producing gas in that condensate. And Alaska is growing, it’s oil, Spraberry is still growing. And then you have Raton that’s more flattish, Edwards slight increase with our – we have still, a Tim mentioned, several gases shut-in that we will be brining on here in the next month or two. And then you have I think about 1000 barrels a day from VPP volumes that’s coming back, that’s primarily gas. A combination of both, so –. Your old projects are still primarily growing in the company. Your gas projects are generally flat to maybe a small decline when you include Mid-Continent in there. And that’s primarily due to the wide differentials.

David Kistler – Simmons & Co.

Great. Thank you. Thanks a ton on that. Then kind of going to the rigs, the 17 rigs that you are letting go, what portion of those where under contract on a term basis, you know that as a result you are incurring that charge? And then of your remaining 11, are those all currently on term as well?

Scott Sheffield

Yes. The rigs that we are looking at terminating, they all had very favorable termination charges. The termination charges were 30% to 40% off of the current day rate. So, that is one of the reasons we looked at, we get a very favorable termination charge. And that’s why we are terminating. So, we are not going to bring these – any rigs back for probably at least six months or longer, probably six to 12 months, because we think it will take that along from the service costs. So, basically, three contractors that had very favorable termination charges is why we are terminating those contracts. Most of the contracts ran out primarily by the end of 2009. The rigs that we are keeping, most of them run out next summer. We are getting much more positive feedback in regard to immediate cost reductions.

David Kistler – Simmons & Co.

Okay. Great. That’s very helpful. And then thinking about just generally reductions in production, can you walk us through any transportation agreements you might have or at least I know you have some 2011 commitments. Did those change at all, how does that go through?

Tim Dove

No. No effect with transportation agreements at all.

David Kistler – Simmons & Co.

Okay. Great. That’s very helpful. Let somebody else jump on.

Scott Sheffield

Thank you.

Operator

Next we have Michael Jacobs with Tudor, Pickering, Holt & Co.

Michael Jacobs – Tudor, Pickering, Holt & Co.

Good morning everyone.

Scott Sheffield

Hey, Mike.

Michael Jacobs – Tudor, Pickering, Holt & Co.

Starting off, kind of with the CapEx. I am trying to reconcile the $500 million to $600 million in the annual CapEx to keep production flat post 2010 with the $200 million that maintain spud production over the next two years. Just kind of thinking using ’09 as an analog and thinking about your – in the back growth of 7,000 barrels a day to 8,000 barrels a day from Alaska, South Africa, South Edwards. Does that say that base company declines by 7,000 barrels a day to 8,000 barrels a day if you were to spend only $200 million in ’09? And that you would get the next 7,000 barrels to 8,000 barrels at $300 million to $400 million. So, is that the right way to think about it?

Rich Dealy

Yes, it is close. The purpose of the $200 million, obviously we don’t think that we are going to see $60 and $6 for the next two years. The purpose of it is that we can get down to $200 million, and there is a slide in the Appendix that gives the detail and the backup to that, that we could spend $200 million in ’09 and ’10 and keep production flat. And obviously, if I’m only spending another $300 million – and that $200 million by the way is primarily – continue to drill in Alaska. It’s about $100 million to $125 million of the $200 million. There is lease bonuses in there to maintain leases in the worst case scenario. So, for another $300 million, we can basically add roughly about 5% production growth.

Michael Jacobs – Tudor, Pickering, Holt & Co.

Okay. That’s great. And then just moving on to your two major assets. It seems like you are dealing with a perfect storm of low prices, wide realizations, high cost. Can you convince us that something hasn’t changed in the Spraberry and the Raton in terms of asset quality?

Rich Dealy

Yes. Nothing has changed. We’ve been drilling Spraberry wells for 30. We drilled first of all 5,500 wells. So, we have another 20,000 wells to drill. In fact the wells have gotten better since I’ve been associated with the Spraberry for the last 30 years. We are getting a – in fact we are still highly encouraged by the 20-acre spacing. We are highly encouraged, we are still moving forward on the waterflood, as Tim mentioned. We are getting additional oil from the pay zones. And also we are getting a bigger acreage position in the Wolfberry were we are drilling several Greybergs and Hendricks prospects. And we are getting shows as we drill for those in the Spraberry Trend area in 2009. The only thing that has changed, we just don’t feel in this environment a 20% return at current well cost of $1.4 million is worth drilling, running 17 to 20 rigs. So, we got to get the cost down. When we get the cost down, we are probably over can look at owning more and more of our own equipment. It’s worked in Raton to keep cost in check; probably we’re looking at that seriously. We talk about moving the frac crew down to keep cost down because we got to keep the machine running. If it weren’t for the sudden collapse we would not have reduced the rig count. So, it still a great asset and we are still going to move forward, and it will be the drive engine for the company, and the reserve booking over the next 10 years.

Tim Dove

Okay. I had a commentary of that, Michael this is Tim. You know I would say this has absolutely nothing to do with asset quality. As Scott alluded to, this is a manufacturing process for us. We got 890,000 acres out there, most it is HBP. We don’t have to drill these wells and there is no sense in a manufacturing analog making we just – we are not making the kind of returns and we can lay these rigs down, get cost down and we will be back to margins that makes sense. So, in fact it’s the opposite of what you said. I think these assets are proving to be the highest quality oil onshore assets that are out there.

Michael Jacobs – Tudor, Pickering, Holt & Co.

Scott and Tim, that makes sense, and everything you are saying makes a lot of sense. But just to make sure I understand the CapEx cuts and I reckon that that you haven’t finalized the ’09 budget. And recognizing that you would rather buy stock than spend capital that doesn’t reach your hurdle rate. All of that makes a lot of sense. And the release and presentation certainly let you service providers know how serious you are. Have you gotten any initial reactions from primary drilling workover completion service providers? Have they contacted you once you put the information out there or is it just too soon?

Scott Sheffield

Yes. We’ve gotten all kinds of reaction ranges from we are not going to cut it all to we are cutting 20% or 25%. So, it all depends on who you talk to, how big the company is, what their backlog is, like pumping service companies generally – there is such a shortage of wells to be fractured in the whole onshore US. It’s going to take a longer time frame for them the rig count to come down for those cost to come down. And steel, for instance, we saw steel get up to $1,100 a ton just recently. It’s dropped $300 to $350 a ton in the last 30, 45 days. So you would think we’ll get a 30% reduction. In our tubular, we’ve only got an 8% reduction. We’ve been told it will take another three to five to six months before that all filters through. So those are examples. Polling unit companies. Some have already dropped 25% to 30% per hour some of the ones that we are using. So, those are some of the examples.

Tim Dove

Yes, that’s proactive too. We are not waiting on people coming to us. We are going to them, Michael. So, those meetings, several have been undertaken, more will be undertaken as well. We’ll be going ahead.

Michael Jacobs – Tudor, Pickering, Holt & Co.

That’s great color. I really appreciate that. Just one final question. For those of us who haven’t been on your side of the table, can you walk us through the economics. How do you spend $40 million to $45 million in the termination costs and recoup those lower costs going forward and how much do day rates need to drop to justify that expenditure?

Rich Dealy

Yes, the $40, $45 million was about 30% to 40% of the current day rate. Okay, decision that we had make do we over spend the next six, seven, eight months pushing the growth profile. We could announce the 12% to 14% production growth, but right now the strip for 2009 is about – it’s moved up obviously in the last two or three days, it moved up to a roughly $75 and $7.70. It got as low as $6.80 and roughly about $67 recently.

So, we’re still very pessimistic that the commodity price first of all is going to be in Contango and is going to move forward. I just don’t see enough rigs shutting down yet to drive down the big potential gas storage and gas supply issue until people get more and more serious. Obviously, we’re trying to send a message and so, if we would have kept the $40 million moving forward, it only represents about 15% to 20% of our total expenditure.

We would attribute that to another $500 million expenditure and we could be easily overspending over the next several months, unless we hedge. The choice was, do we hedge a 100% of our commodity at $7.70 and $75. We decided not to do that at this point in time. We think there is more upside, we’ll get aggressive on hedging if we see it get up into the $88 range or higher, then bring in more cash flow. But those are the choices we had, so we did not want to go into a big overspending cash flow mode over the next six, seven, eight months.

Michael Jacobs – Tudor, Pickering, Holt & Co

That makes perfect sense and so, if your providers came to you on Friday and said we’re going renegotiate everything 20% to 25%, the old plan seems like it would be back in place?

Rich Dealy

Exactly.

Michael Jacobs – Tudor, Pickering, Holt & Co

Right, thanks guys. Sorry for the long questions.

Rich Dealy

Yes.

Operator

And next you have a question from Gil Yang with Citi.

Gil Yang – Citi

Just a point of clarification first; on page six, when you give the returns in the price at the various prices, those are unhedged prices, is I right?

Rich Dealy

That’s right, Gil and it is flat for the 60 years of life for the Spraberry well.

Gil Yang – Citi

Okay. Can you talk about, obviously you have drilled – I think you said 5,000 wells there. What progress have you made in – and obviously there is huge potential there, but that 60 year life is sort of scary in some respect. What have you been able do to accelerate that and/or just reduce the costs of those wells?

Scott Sheffield

Yes, we are on a plan as you know to ramp up the 30 rigs, which is in prior presentations are about 700 wells per year, I think about 2011, right Tim? Obviously, what’s happened with commodity price downturn, we have got to take a different view. In other words in the future, what we have to look at in regard to protecting running 16, 17, 20 rigs or 30 rigs and some of the things we’re going to do is basically probably tend to own more and more of our own equipment. We probably do some more on hedging or buy inputs as we see prices. So, we don’t go through ramping up to 20 rigs, back down to seven, backup to 20, 25 and 30. So, we’ll put more protection things and buy some more equipment to get the inventory drilled and we’d like to get up to 1000 wells per year at some point in time, is the goal.

Tim Dove

We already drilled these wells 20% to 30% less than the competition. That’s really we’ve accomplished over the last several years.

Gil Yang – Citi

Okay. When I meant acceleration, I didn’t mean activity, I actually meant what can you do from an engineering perspective to frac the well better to either putting bigger fracs in or changing the frac fluids or the profits or whatever to get the volumes up more quickly?

Scott Sheffield

No, the two big improvement that we have made is the silt/shale intervals, where we’re adding additional reserves and production to early testing.

Gil Yang – Citi

Okay.

Scott Sheffield

And secondly by going deeper into the Wolfcamp, we’re making much better wells fairly with a $10 fining cost at yesterday’s cost, which will go down. We’re adding the Wolfcamp and making much better wells. That has been the biggest positive in regard to a typical Spraberry (inaudible) well, is adding the more shale, silt shale and adding more Wolfcamp, for getting more reserves on higher production rates.

Gil Yang – Citi

Okay. Could you just give us a review of the – I think you have drilled two wells so far in that silt/shale interval. Can you gives us an update on how those wells are doing, I think the first one you said was – initial production like 50 barrels a day. How is that doing three, four months later and how is the second well doing?

Tim Dove

Well the first well of course, I have mentioned this in my comments, Gil, has done exceeding well, very flat production is any given day being 45 to 50 barrels a day and that is producing only as I mentioned from one of the non-traditional zones in the well. We plan now to move to produce another non-traditional zone up the hole and then further more one of the traditional zones to get a feel what is the contribution from each? The second well will then be the target of completion, we have not yet completed the second well.

Gil Yang – Citi

Okay and so this flat production curve is different from the normal Spraberry sand well?

Tim Dove

Yes, I think it is a case that we are positively surprised, but the fact is well as been relative to level on production, as you know, looking at our tight curve, it is not unusual to expect pretty reasonable declines in the first several months of year of production. So we definitely been encouraged to see that result.

Gil Yang – Citi

Okay and then finally, the – 30 feet – up to 30 feet of pay is only from this one non-traditional zone?

Tim Dove

No, it is out of the whole core barrel section and we pulled about 650 feet of core, this is – in small interbedded silt stones among different shales and it just calculates to about 30 feet out of the 650 recognizing, when we calculate our resource potential of the Spraberry Trend area, we use an average of 65-feet of net pay before this interval. So you could see, it depends on the quality of rock and its contribution, but it could have pretty good potential.

Gil Yang – Citi

So as after this one well is producing roughly 45, 50 per day, how many feet of intervals is it producing out of?

Scott Sheffield

I don’t know exactly, what number of feet we have completed it in, can we get back to you on that, Gil?

Gil Yang – Citi

Sure, but it is a fraction of that 30, right?

Scott Sheffield

Yes, well it is – as one particular non-traditional zones, which produce or maybe two of the exact – how many exact intervals so the attritions on several different intervals, but they are all non-traditional I have – I simply have to get back to you on that.

Gil Yang – Citi

Okay thanks.

Operator

So next we have Joe Allman with JP Morgan.

Joe Allman – JP Morgan

Yes, hi everybody.

Scott Sheffield

Hey, Joe.

Joe Allman – JP Morgan

Hey, Scott how sustained do you think are these abnormally wide basis differentials, and in your view, what are the drivers and what are the fixes?

Scott Sheffield

Yes. The first fix obviously, we are evaluating whether or not to go in and hedge aggressively the basis differentials of over the next several years. The basis differentials go down substantially over the next five years. So that is first thing we are doing at a company level.

Second thing is, we need cold weather short-term and we need a second piece of Rockies express going east put in service in 2009 and then the third thing is we probably need about 500 rig count reduction in gas drilling.

Joe Allman – JP Morgan

Okay so you think – so you think is just too much production Rockies express, how much do you think the problems with the processing plants has been of part of the wide differentials?

Scott Sheffield

I don’t think processing plants has caused an issue with natural gas prices.

Joe Allman – JP Morgan

Okay and then in terms of your plant cuts, when you are looking at economics, are you assuming that we are going to keep these wide differentials or do you kind of normalize the differentials when you are making decisions about dropping rigs?

Scott Sheffield

We are assuming we will have to make a decision whether or not to hedge aggressively differentials as some companies have done recently as we start back the rigs, we probably be intend and we will be hedging aggressively, differentials only, maybe not the non-mixed price. And at the same time, once we do that – after that, we will be bringing some rigs back.

Joe Allman – JP Morgan

Okay.

Scott Sheffield

Like Edwards, Raton mid-Continent area places of Barnett, places like that.

Joe Allman – JP Morgan

Okay so when you look at the – if you look at it, feeling the economics right now when you are using whatever pricing on the strip or whatever, are you assuming that there is a greater than normal differential for whatever the next 12 months or so?

Scott Sheffield

Short-term, it maybe six months for sure

Joe Allman – JP Morgan

Okay, great very helpful. Thank you.

Operator

And we have a question now from Leo Mariani with RBC Capital.

Leo Mariani – RBC Capital

Yes, a quick follow-up on the Spraberry here, obviously you talked about getting some additional production contribution of your silt and shale zone there on Spraberry. What will be the incremental costs to bring that on, if you guys were to commingle within the more traditional zones?

Rich Dealy

Yes very little, probably $40,000, which would be addition to the frac job, so almost insignificant.

Leo Mariani – RBC Capital

Great, okay. In terms of the second well here, it sounds like you folks are planning on doing that. I think you are going to have results in the next couple of months and are you going to announce that if you get something?

Scott Sheffield

Yes, but I hope it will coming the same 45 to 50 barrels a day and just sort of stay flat. So, that is what we hope happens, instead of going on an immediate decline.

Leo Mariani – RBC Capital

Got you, okay. With respect to the waterflood project that you guys talked about in the Spraberry next year, it sounds like you are going to keep going with those. Can you provide a little sense of what the economics are, starting to waterflood some of that existing production and maybe contrast that with the drilling of new wells in Spraberry?

Tim Dove

Leo, we are going to have to drill some new wells in the waterflooded area, to make sure we have fully 40 acre drill, so you will have the normal drilling economics. Hopefully, that improves what we have been talking about as we drill the wells to complete the 40 acre pattern. The other thing we will be doing is drilling some injection wells. In some case we will be converting current producers to injectors and the economics look something like this, it will based on current costs, not necessarily where they may go, but we will be converting a current producer into an injector at the rate of about somewhere between $100,000 and $200,000 and, to the extend we did a drill new injector based on old costs where a well would cost typically $1.4 million, might be a $1 million in the old cost regime to drill the injector.

So, we will probably be, as I said doing a combination of those exercises. The economics are excellent though because at the same time that we have now be introducing water in system, what we are in effect doing is injecting produced water, which reduces our LOE, reduces our water handling, our need to truck water out of the areas and so on. So, there is LOE benefit you’ve got to put in the equations as well.

Overall, we have seen empirically that we tend to get a pretty rapid bump in productions to say six months after introduction water to the tune of sometimes 2x or 3x what the area was prior to that producing. So, the economics are very good on that basis, and as I mentioned to you in our meetings and other investors, we are looking at probably for every barrel that area was going to produce on primary, it will now produce 1.5 barrels. So, 50% bump in EUR is substantial based on the fact it is not the costly to put in place.

Leo Mariani – RBC Capital

Got you. Okay. In term of your Gulf of Mexico shelf production I think you guys will have around 2,000 barrel a day offline. Any update as to when that may return at this point?

Scott Sheffield

Well, we still have oil curtail as we speak some 1,200 to 1,400 barrels a day curtail and we really don’t have much insight into that still because really it’s downstream pipeline issue there are concerned. We’re ready to produce, but there really is no visibility because of all the activity that is needed in the Gulf of Mexico to get things prepared. This is simply on a long list, so we really don’t have any visibility where it’s going to comeback on.

Leo Mariani – RBC Capital

Okay, I guess just final question for you guys here. In terms of what production you have in the gas side, it’s not subject to Mid-Continent pricing. Is that basically your offshore and Edwards Trend?

Scott Sheffield

Nothing really, very insignificant offshore and Edwards Trends is the only other gas. Even through Houston ship channel has blown out to historically as $0.10 to $0.30. It’s blown now in October, November to $0.75.

Leo Mariani – RBC Capital

Okay. Thanks, Scott.

Scott Sheffield

All gas plays are being affected in regard to the differential.

Leo Mariani – RBC Capital

Okay, thanks for your time.

Operator

And next we have Rehan Rashid with FBR Capital Markets.

Rehan Rashid – FBR Capital Markets

Good afternoon, Scott.

Scott Sheffield

Hey, Rehan.

Rehan Rashid – FBR Capital Markets

Just kind of taking queue from the earlier line of questioning, indeed I think the two broadest questions in my mind is just getting comfort with the quality of the exciting assets and also just being comfortable with the fact that long-term growth potential has not been impaired. You guys talked a little about the Spraberry, 20% IRR. I have a quick, quick question on that front, if you burden this with kind of corporate G&A or interest, what does that translate into in terms of returns from an aggregate standpoint?

Scott Sheffield

Yes, after tax it’s about a 12%, 13%, 14% return and when you run through the balance sheet it just to me it’s not a return that we think it’s worth drilling to get a 20% returns. So and that’s why we historically have always try to achieve a minimum of 40% and that’s we feel like we’ll get there.

Rehan Rashid – FBR Capital Markets

Got it, in terms of the cost $1.4 million to drill the Spraberry well, a rough break down on to how much is drilling? How much is completion? And whatever else that might be?

Scott Sheffield

Yes, drilling is probably 15% to 20%; frac job is 15% to 20%. Tubulars are about 15% to 20%. So those three components make up 50% to 60%. Everything else is going to be miscellaneous, such as pumping unit will be your next biggest item, it’s probably 3% to 4%. So there is a bunch of item in the 2%, 3%, 4% range.

Rehan Rashid – FBR Capital Markets

So all of the total cost maybe only 20% shows some amount of stickiness and the rest should trend down?

Scott Sheffield

They are all going to show trend down. We have had a – and one of the primary reasons we’re keeping several rigs running. We have had tremendous negotiations with certain drilling contractors and now with others, okay? So we’ve seen significant decreases already in drilling contract rates with certain drilling contractors along with others. Pumping services will takes slower to come down. Tubulars, as I mentioned earlier, will come down slowly. We have got an 8% decrease already. We think it will end up being 20% to 30%, but it will take six months. So those are some examples.

Rehan Rashid – FBR Capital Markets

What would Raton gas IRR look like under that kind of similar analysis? What would be your current IRRs?

Scott Sheffield

Yes, Raton is very similar 20 to 22, at $6 flat gas. That’s used in the – because we have our own equipment there. The primary reason we are stopping there is simply because of the wide differentials. The horizontal Pierre and the vertical Pierre as Tim said. The vertical Pierre’s are doing much better the last few wells than expected due to new stimulation techniques, but it’s again it’s back to the differentials. We got to make a corporate decision whether or not to aggressively lock in differentials over the next several years.

Rehan Rashid – FBR Capital Markets

As you think about re-ramping your CapEx. Is there any particular order in terms of projects that you would go for first with the mix remain kind of same as it has been?

Scott Sheffield

I think Spraberry will be the focused, number one, and then two I see Raton and Pierre coming back. Obviously we’re excited about what’s going on the Eagle Ford as to add to the Edwards potential. So obviously we can see plays there and then eventually bringing the rig back in Barnett.

Rehan Rashid – FBR Capital Markets

Got it, one last question on stock buyback. When can you resume, what’s your remaining authorization? Are there any restrictive covenants that would not kind of let you buy back as much as you want to?

Rich Dealy

Yes. There is $450 million left of our $750 million program, and we can start back 48 hours after today.

Rehan Rashid – FBR Capital Markets

Got it, okay and what was the average purchase price of the $2 million that you bought so far?

Rich Dealy

$2 million was primarily third quarter. It’s around $50.

Rehan Rashid – FBR Capital Markets

Okay, alright thank you.

Operator

And next we have a question from Monroe Helm with CM Energy Partners.

Monroe Helm – CM Energy Partners

Hi, thanks a lot guys. Two questions, can you give us a little bit of your color on what reasons are causing the Mid-Continent gas prices to be as low as they are relative to the other regions, is it a function of demand, utilizing more Barnett gas less Mid-Continent gas, any thoughts on that? This is the first question.

Scott Sheffield

Yes, Monroe I addressed it earlier but I have just – it's not just Mid- Continent area. Mid-Continent the first trunk of the Rockies Express line goes in Missouri, so all the pipes go to Missouri from Mid-Continent. So, Mid-Continent and Rockies gas all go the same place and they can’t get out.

Monroe Helm – CM Energy Partners

Okay.

Scott Sheffield

It can go to Chicago, but it can’t get into the further Northeastern markets.

Monroe Helm – CM Energy Partners

Right.

Scott Sheffield

Until Rockies express. The second expansions happens, it was delayed. Permian of all areas we are seeing Barnett Shale, half the Barnett Shale is experiencing a 300 to 350 differentials now. Most of it, a lot of it’s priced up a lot (inaudible) getting 300 to 350 less. Houston ship channels getting $0.75 less. To me there’s too much gas in the system. Our storage is essentially full, as too much gas in the system we got too many rigs run.

Monroe Helm – CM Energy Partners

Okay.

Scott Sheffield

So gas on gas competition, so it’s not just Mid-Continent and Rockies now, it is all over.

Monroe Helm – CM Energy Partners

Okay. And I am sorry I missed your comments from earlier. I got on the call it. Second question was, when you look at the members of the credits facility you have and all lenders that are involved there, I guess two questions, how often do they review the credit facility and once next review due, and do you have some concerns with any of these people in your bank lines under some pressure, because the other parts of the banking system are having problems, that they are under some pressure to reduce their exposure to the oil industry?

Rich Dealy

Helm, it’s Rich. We don’t really have a review requirement in the credit facility, it’s good through 2012 as we’ve mentioned earlier and really – we frequently talk to the banks and typically have bank meetings once every – one or two years with them. In terms of the banks that we have on our credit facility, today I am not any big concerns about any of them. Obliviously there have been – the banks have been less in the headlines for a last couple of weeks and so hopefully that bodes well the things are improving on that front. I think on the other side in terms of where we go from here, I mean I think it some of those banks wanted to reduce their exposures, and some have moved some exposure over the last couple of months into other banks. We’ve had other banks those have come in and pickup that capacity. So I have really today think everything is fine and don’t really expect any problems. That’s not to say, they can’t happen, but I think things are improving.

Monroe Helm – CM Energy Partners

Okay thanks for your comments.

Tim Dove

Hey, Monroe, one other comments is that, in discussions with some of the banks people who have reserved based lending versus unsecured, the banks are going to be most likely using a $45 price deck, coming up in the next by end of the year and so that is going to be the next shoe to drop.

Rich Dealy

And we are unsecured, we don’t have a borrowing base, but obviously those that have borrowing base it’s a bigger issuer.

Monroe Helm – CM Energy Partners

Alright you know what gas (inaudible)?

Tim Dove

They can take about 70% of strip pricing so closed up $5 probably.

Monroe Helm – CM Energy Partners

Okay that could create some problems for some of these people I will say?

Tim Dove

Yes. So hopefully we will see some rigs drop.

Monroe Helm – CM Energy Partners

I would think there is a pretty safe assumption if that’s what’s going to happen to these borrowing base, or lending facilities. Well thanks again for your comments.

Tim Dove

Okay.

Operator

And Mr. Sheffield with no further questions in the queue, I will turn the call back over to you.

Scott Sheffield

Okay, again thanks appreciate everybody’s questions and again we have great confidence in our assets and we are going to resume this growth profile, but we think it is more important to some other things. Be prudent, very prudent with the capital over the next six to nine months. Look forward to the next quarter call in February. Thank you.

Operator

And this does conclude today’s conference. Thank you for attending and have a wonderful day.

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Source: Pioneer Natural Resources Q3 2008 Earnings Call Transcript
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