先鋒自然資源 (PXD) 2008 Q3 法說會逐字稿

Welcome to Pioneer Natural Resources third quarter conference call. Today's call is recorded. Joining us today is 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 these slides relating to today's call is www.pxd.com At the website please select Investors, then select Investor Presentations. Comments will be 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 risks and uncertainties that could actual results 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 two of the slide presentation and in the most recent public filings on forms 10-Q or 10-K made with the Securities and Exchange Commission. At this time, for opening remarks and introductions, I would like to turn the call over to Pioneer's Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Good day, everyone, and thank you for joining us. Let me review the agenda for today's call to get things started. Scott's going to be the first speaker. He'll go over the financial and operating results for the third quarter of 2008. He's then going to highlight Pioneer's current strong financial position and initiatives that we have recently implemented to maintain financial flexibility and improve returns in response to the 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 the year. Rich will then cover the financial highlights from the third quarter and provide earnings guidance for the fourth quarter. After that we'll open up the call for your questions. With that, I'll turn the call over to Scott.

Thanks, Frank. Good morning. We'll start on slide number three, Third Quarter Financial Results, Pioneer reported a net loss of $0.03 cents a share. It's primarily impacted by the two hurricanes, where we lost about 3,000 barrels of oil equivalent per day in the Permian Basin and 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 or November. Just to remind everybody, 80% of our gas, 85% of our gas, domestic is located in the mid continent, Permian and Barnett. The Raton we tied at mid continent pricing. So 80% of our gas today is getting $2.80.

The differentials have widened, and have extended and gotten wider in October and November. In addition, we have most of our Tunisian South Africa oil at the end of the quarter, at much lower end quarter end prices by estimates by analyst. We had significant non-cash charges. We had a Uinta [peont] impairment, did a low gas price and wide differentials. Our assets there. We eliminated ongoing operating and carrying cost with 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 types of investments are not worth going forward.

We did announce a while back our Syncrude potential allowance. We went ahead and took an allowance for Syncrude 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 $0.91 cents per share. We'll continue to reduce shares as we have for the last two or three years by another 2 million shares in the third quarter, and also in October, and we think it's important to immediately deliver a free cash flow model going forward.

Slide number four, Operational Highlights for the Quarter. We started this over a year ago, but we did receive approval by Railroad Commission of Texas to downspace 20 acre -- downspacing that will give us 500 million barrels, putting into the probable category, which will allow us to achieve very low finding costs over the next several years, as we continue to develop the Spraberry Fieldsover that time frame. It was unopposed. Had total support from all of the operators in the field. So highly encouraged by that action. In addition, continuing -- and Tim will update you.

We've had great results from our 20-acre drilling, similar to [40-acre] drilling and also with the encouraging core analysis and shale interval testing, we're seeing more upside to the numbers that we've given out on both 20-employee acre spacing as we open up more pay zones. We are continuing to increase our Wolfberry Trend acreage, about 30,000 acres in the play. This is an area where several wells are making 100 barrels a day or greater, and that's where our remaining seven rigs will be focused on primarily. The 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 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 two weeks ago. It's in the horizontal stage now. Obviously, we were going to wait like we talked about Pierre, we were going to wait and produce the well for six to 12 months before we drill two wells, produce them, before we let the market know. So obviously excited about Petrohawk's discovery. We're highly encouraged by what we see through all the wells that we've drilled, Edwards wells through the Eagle Ford in that play. We also had two Tunisian discoveries, one at -- more Edwards discovery. And finally our almost prolific South Coast gas project, gas well came on production.

Slide number five. After several meetings in the last several weeks, the management, in looking at history, we decided it would be very prudent in this low price environment. We saw crude touch $61, just recently. We saw gas touch $6.20. Obviously, the market's in contango, which I'm still not highly encouraged in regard to prices immediately getting back to the [$80, $88] or some price even above that. We could easily move forward with the low prices.

As we have seen in past down turns, the market stays in contango and moves forward. Generally people continue to drill through the cycles. They overspend cashflow. History has shown most companies end up delivering poor economics. It's probably generally the worst time to drill, when you're drilling at the top of the market. With service costs you're getting lower commodity prices. We've decided to take a different approach, and that approach is significantly reducing the rig count, significantly improve our strong financial flexibility, and essentially it's better to be buying stock at $5 to $6 of 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're already starting the see some costs come down, but it generally takes, in meetings that we've had over the last several weeks with service companies, it will 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've got $735 million in 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'll see in December,CapEx is expected to be obviously less than $1.3 billion, somewhere between $1.2 and $1.3 billion for the year. We've hedged 20% of our oil production with $100 floors and $190 collars in 2009 and 2010. We have legacy hedge and VP expirations providing significant cash flow in 2009 and beyond. There's a chart in the back of the appendix, it talks about that.

We feel like we need to operate as if we're in a $60 oil and $6 gas environment. It may last for several months. By 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're getting $2.80. Permian Basin, Barnett, Mid-Continent and the Raton. So we need both gas differentials to improve significantly, and well costs to improve the return back to the return, to which we'll talk about that we showed. Reducing 60% of our rig activity until costs approach 2006 levels, we're targeting 20% to 30% cost reductions. We've already seen about 10% to 15% in certain of our key areas.

In addition, reducing well service units, primary in Spraberry Trend area field, from 42 to 30, which are obviously significantly lower operating costs. We have 15 remaining units, and we'll continue to divide more units over time, to help drive the cost down, because we can operate the cost -- the service units much cheaper, than we can by renting from third parties. We also think it's important to deliver free cash flow and not continue to have a strong production profile in overspend cash flow and take the risk that commodity prices will bail us out in this marketplace.

We expect -- what's unique about our asset base is the fact we can have a 60% cutback, and still grow 5% to 10% production growth in 2009 to significantly reduce our 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 you 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 six, gives you an illustration of returns of our key asset, the Spraberry, which is about half of the company. All of our assets will have very similar returns during 2005 through current. The exceptions would be Tunisia, which still has the best returns in the company, and Alaska, which has great returns, primarily due to cost forwards. This is primarily Raton, Edwards, Barnett, and and Spraberry Trend areas.

We use Spraberry as an example. You can see what's been happening in regards to the returns. We've generally been getting historically about a 40% return over the last several years, which is a great return. We saw a significant rise in service costs. Service costs had doubled in a typical Spraberry well in 2005 to $1.4 million, and all of 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 $1million dollars. With the rigs we have running, we've already got our costs down already to 10% to 15%. Certain drilling contractors, which we won't mention names, have been easy to negotiate with, very accommodating, and certain ones haven't. Obviously, as we see rig contracts expire, we will begin seeing costs coming 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're confident it will happen. It's just not going to happen overnight, as we've seen commodity prices decline.

Slide number seven, this gives you a little bit of rundown on some of our negotiations and what's happened in the rig count area. Again, this is primarily done because we feel like costs will come down significantly. So we're taking a termination charge of about $40 million to$45 million, which really reflects $500 million of expenditures. We feel like it's 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's 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 showed.

We've 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 the Spraberry Trend area, for instance, to reform our own frac jobs down to a million dollars.

Slide number eight, again, shows the consistent performance of our asset base over the last several years. We'll 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're still growing somewhere between 5% and 10% in a very, very low commodity price environment for 2009. On a per share base, we've averaged 17%. We're estimating through the end of 2008.

Slide number nine, really an update on some of ours assets. Again, our assets performing at or above expectations. We've had strong production growth performance, 18% over the last 12 months, nine months of '08 versus nine months of '07, primarily driven by core assets at 23%. Spraberry, Raton, Edwards,Tunisia and Alaska. We still expect 2008 F&D costs to be in our range of $15 to $20 for BOE. This does exclude price revisions. We do expect if the wide differentials go out from 31st of this year, we do expect to lose somewhere between 10 to 15 million barrels of long-life gas reserves out to 50 to 60 years. Which have a 0% PV effect. In addition, we expect to lose somewhere between 10 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 out about 60 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 booked, the primary Pierre performance from the horizontal and also from KP 2 and 3, the Spraberry shale intervals. Additional Barnett opportunities that we have picked up in acreage. And also the Eagle Ford is not in our number also, which we'll know the results over the next several months. To restore back to a 14% production per hare per growth target, we feel like we need to get to $80 oil and $8 gas, really sustained environment that we're confident in. We feel we'll get back there, whether a month or six months or two years, we don't know. But we'll be back there, and the company will be growing again strong, at that point in time.

In 2009 it's more important to deliver free cash flow in 2009 Be very prudent with your capital, continue to reduce shares, reduce debt. We've 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.

Thanks, Scott, and I'll start doing so by turning to slide 10. The 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. That was even considering the fact we had such significant curtailments and shut-ins due to the hurricanes and their effect on the 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 our 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. Then getting back to our normal position, where 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. Now Scott has already alluded to the rate 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. When margins improve, we'll be raising those rigs. But the fact is we're the dominant driller. We're the largest player. We think we can effect cost decreases pretty rapidly by taking these actions. The objective is to return to a more normal return set of return metrics looking ahead.

And in slide 11, we are confident in saying that even with all the market turmoil that we've 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 light of the current situation in terms of 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 alluded to the fact that the Railroad Commission of Texas approved the field oil change. We are still in the process of drilling our 20-acre campaign for the year. We have a total of 23 wells planned. In fact, we've already drilled nine of those, and continue to see very positive results. We're seeing the wells come on typically in the neighborhood of 40 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 are 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've done about a 6,000 acre area under one of our existing units that we'll be progressing the water flood for 2009, including drilling several injection wells and converting current producers to injectors, and in addition which, we'll be needing to add more wells in terms of 40-acre drilling producers as well. So overall, the project is looking good. We're proceeding with that with all due haste as a 2009 project. The overall objective, of course, in the longer term sense is unchange. That is in those sections where applicable, getting the recovery rates up to 27% to 28% where they would only be 12% to 13% on the same sections based on traditional 40-acre field development.

We're 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 of core. Further review shows we think we've added on a net basis about 30 feet of additional pay. We're going to process it of course, by testing these wells, of evaluating how much contribution of resource potential that can give us. Too early to state that, but nevertheless we think that these nontraditional intervals will, in fact, add EUR to the wells. And we're making still about 50 barrels a day, by testing only the non-traditional zones in this silt/shale interval. And we'll 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 to the 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 six fold increase in production after stimulating the well. We're on the last five that we have planned for this year, and at this time, we're cleaning up the lateral section to begin the completion process, and we'll have to evaluate next year whether to do any more horizontal activity. We were considering a potentially grassroots horizontal well next year, and that, of course, will depend upon what we think about commodity prices at the 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're making a lot of progress Beth with regard to completing our methane drilling, as well as our Pierre shale program. The vertical shale performance that we've seen in some newly drilled wells that have been put on production continue to show that the 40 -- the vertical Pierre shale program, KP 1 only, and now additionally adding some KP 2 and 3 zones have excellent results. And in fact, we've seen results that indicate to us that, again, we're probably adding in the neighborhood of 20% to 30% in terms of additional contribution by coming up hole and completing the wells in the KP-2 and 3 as well.

Importantly, I had hoped to have results for you for the results of the two horizontal shale wells we're drilling in the Pierre. At this call these fractures are taking some time but we're making very good progress. We already have three stages fraced in our first horizontal well. We have two remaining stages to pump. Probably, we'll be done in the next couple of weeks. The results look very good in the early stages. Our image logs that we run down hole show significant fracturing in both the 2000 foot laterals that we drilled, and that gives us a great deal of encouragement. From there we'll move on to prepare to frac the second well. Suffice it the say we don't have any results, but overall from the standpoint of what we've seen from a technical standpoint, we're encouraged.

We are going to be reducing our drilling along the lines of what Scott had mentioned in this area. Owing to the fact that the gas differentials are extremely high. That is to say, our net [metri] low based on this gas being tied into mid-continent pricing. And we'll look at a 2009 program that is currently curtailed, but we'll 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, that's site 13, excellent results. As you recall, we went into the year with about a 25% annual growth rate target. Now we still continue to believe we're going to do over 40%. In fact, our current production is over 80 million cubic feet a day as we put in one of our three [aiming] training facilities and have two more to add during December. And accordingly, we feel pretty comfortable, we'll be able to tie in the 10 million cubic feet a day on a net basis that is currently shutting waiting for that treatment. We did make a new discovery of the trend, a 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 reducing the rig count here from six to two, and accordingly we'll drill a few less wells in 2008. It's again in relation to what's happening with gas differentials. We'll be evaluating 2009 as I mentioned in relation to Raton in the same vein. That is, when margins improve to dictate the economics are strong.

We are completing our large seismic shoot. It's 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 we simply couldn't see on 2-D alone. We're pleased of what we'd seeing there in terms of the Edwards 3-D shoot.

Speaking of Edwards and speaking of south Texas, we have another slide in here, as Scott alluded to our interest in the Eagle Ford shale, shown on slide 14. I thought it would make sense to discuss our interest in the Eagle Ford shale. We 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 LaSalle 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 there through the entire trend.

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 to the Eagle Ford, because the Eagle Ford directly lies over the Edwards that we're drilling the reef play. And it's the case that as we drill through here it's frequent that we have to actually flair gas when we're drilling to the Eagle Ford, and we've logged all of this information in all our wells.

It gives us a lot of encouragement to have Eagle Ford ubiquitously spread across essentially all of our Edwards acreage. We know Eagle Ford has significant gas unconventional gas potential across the acreage. We've been gathering the data to be able to progress that, map it and quantify what we think is the potential. And what we believe is that the Eagle Ford is present across all of our acres or at least 100,000 acres we control of that acreage, and based on the sweet spot we think we've identified it's about 30,000 acres we are going to choose to drill our initial wells. The first of which we spud in Dewitt County, the middle part of October. It's about a hundred miles northeast of Petrohawk's discovery, and the objective is it begins the\\o test Eagle Ford on our acreage. We just completed coring this well, and are preparing to drill the lateral section. We should be done with that well, say, in the next couple of months. We'll be drilling a 2,500 foot lateral and will be using the typical multi-stage isolation packer technology and then we'll drill the second well five miles away.

So as we get into the latter parts of 2009 or middle part 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 economics and early evaluations that our current estimate of mean recoverable resource potential within the sweet spot is over 500 BCSE. The cost of the Eagle Ford wells will be essentially similar to the Edwards wells we drilled. They're virtually the same depth. They'll have similar costs. By the time we get through with the infrastructure development, we'll have the ability to tie in with some of the Edwards infrastructure we've been waiting on and putting in place the last couple of years. We also believe we have Austin Chalk potential that sits 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 restructure and is frequently fractured. We 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's currently behind pipe, and we're really also in the process of looking at the resource potential and seeing where our next chance to test the Austin Chalk in '09. That's a recap of a new thing we're looking at. We're pretty excited about it. Turns out we have the acreage in place that we believe can lead to substantial growth in the new play.

Slide 15 is Tunisia. We drilled a couple of discovery wells in the third quarter there. The one of importance there is in the Anaguid block. You see it on slide 15 in the light blue color. It's 940,000 acres. We drilled the first well, testing that technique which has worked so well in Cherouq over the last couple of years, testing the [ocaucus], and tested a well here of 2,300 barrels of oil equivalent a day. It's about half gas and about half liquids, and we'll continue to evaluate the next steps as a result of that discovery. And we also in the second well we drilled that was a discovery in Cherouq are testing it as well. Overall, in the Cherouq concession, which is our major producing operating concession, we had about 70% success.

Turns out that in 2007, we were essentially seven for seven. And in terms of drilling new bumps and new opportunities, from a spot prospectivity case, overall success has come down in 2008. In fact, this year we drilled about two out of six successful wells, and of course, a couple of those we're testing in other zones, such as the TAGI and the [ordavision] that'sa deeper formation, with the success rate falling somewhat in 2008. It's 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 will be affected by it as we go into 2009. We're still producing about 7,500 barrels equivalent a day, [Premoir] 3 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 feed 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.

And slide 16, South Africa, of course, we made the major change now. We produced about 3.8 MBOE a day in the third quarter. But importantly, we have now changed what had been an injection well in the sable oil project to a gas producer in the south coast gas project. It's our largest and most prolific well, and and we have now got that turned around into a gas producer. We had it turned around earlier than we thought ahead of schedule. We're seeing very good rates, very good performance. We're ramping this up as we speak. Currently about 70,000 million cubic feet equivalent per day. Taking it to 80 million to 90 million early next year, and this is simply producing the wells with a gradual basis of increase, without any costs needed to speak of.

Therefore, we can look at substantial growth 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 leasing the Glass Dower, the vessel that was processing sable oil. Of course, with the production having come down, the fixed rate having been so significant, that will -- by it's being released it will have a substantial reduction LOE down from $30 BOE to less than $5. So margins should be improving dramatically in South Africa, not withstanding increases in production.

Alaska is really doing well. Of course, in the third quarter, we were affected by the longer than expected turn around at a third party facility that processes our oil on shore, but that's now back on stream, and we've already reached our exit rate of a net basis of about 3 ,000 barrels a day. We'll be continuing to drill, of course, 2009 and '010. You see here, on slide 17, the rates. Probably about 5 ,000 barrels a day net in 2009. Big increases as we get into 2011, as development continues to grow with drilling wells. The Cosmopolitan, we're still in the process of permitting and in the process of our feed studies, our early engineering studies for the facilities it would take to develop the off-shore discovery. In light of the current uncertainties on oil prices, we most likely will defer the drilling of the well we had planned for 2009 into the following year. And with that I think I'll pass it on to Rich for a review of the third

Great. Thanks, Tim. Starting on slide 18, for the quarter, we did -- as Scott mentioned we reported a net loss of $3 million or $0.03 cents per share. Scott went through the usual items that impacted in the quarter. Those totaled about $0.94 cents, you can see on slide 18. Adjusting for those item's income was $0.91 cents. Obviously before taking into account the differential impact that Scott mentioned and continuing into the fourth quarter. Looking at the bottom of this line, production for the quarter was a 112,000 BOEs per day, at the low end of our adjusted guidance 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 is related to the hurricane effect of having some fixed costs and higher energy related costs that I'll talk about in more detail on a later slide.

Exploration and abandonments for the third quarter, $111 million, this does include $60 million related to the Lay Creek CBM and Delaware shale abandonment that Scott mentioned. Had those not been there, we would have been at the bottom of the range of $51 million in exploration and abandonments. DDNA 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 these activities. Therefore, increasing our DDNA rate. G&A interest expense, minority interest, cash, taxes all generally where we would have expected those to come in. The effective tax rate is just a result of having a small net loss combined with having a higher effective tax rate in Tunisia, where we generate 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, looking at price realizations on oil in the green margin, you can see oil price realizations for the third quarter were down 9% from the second quarter, as Scott mentioned, it's 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, as a resulting in a wider differential when you compare that to average prices for the quarter. Also impacting the Q3 was Legacy hedge. You can see at the bottom under the Q3 column there, that we had $41 of negative impact related hedges. Most of that's attributed to our Legacy hedges that we talked about. And the nice thing we talked about, those go away at the end of this year.

Looking at NGLs -- NGLs for the quarter were up 11% compared to the second quarter. Obviously, it just has taken them longer to re-adjust as they move into the third quarter. I think the more important point as Scott had 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 a widening differentials is the biggest story here, and with 85% of our North American gas being impacted by the wider differentials, we do expect to see a further decline in the fourth quarter, particularly as we 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 of $15.13. Base LOE is where the primary contributor that's really focused on a number of items, but the first being fixed cost associated with the hurricanes, where we had curtailed production, but still incurred the costs and losing the BOEs, impacted that when you look at our BOE rate. We had higher trucking surcharges associated with our salt water disposal. 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 above where 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 down into the fourth quarter and moving into 2009 as a lot of the energy related costs that impact production costs will be lower in today's commodity price environment.

Turning the 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 being -- losing 2,000 BOEs a day associated with the hurricanes and the maintenance and third-party facilities not being back in place until next week, and being back to full capacity. Production costs expect to be $14 to $15, down slightly from where we were in the third quarter, but really expect for more cost savings moving into 2009. Exploration and abandonments $40 million to $70 million, primarily associated with drilling that is ongoing inTunisia and the Edwards trend. DDNA is expected to be $13 to $14 up from where we were in the third quarter due to the price revisions that Scott mentioned that we anticipated seeing in the end of the year and our South Coast gas project having a higher depletion rate. G&A interest expense, minority interest, all our normal run rates 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. 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 stack 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, just 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 net 44%, down from 47% to 48% at year end '07. Credit facility availability is at $775 million. So plenty of capacity on our facility. Also mentioned there that we do our covenant calculations on a quarterly basis. We have plenty of capacity under our covenant. So no issues on that front either. Scott talked about our maturities, our credit facility good through 2012. No significant bond maturities until 2013. In a longer term view, targeting 35% to 40% debt to book capitalization and expect to be there in 2009.

Turning to slide 23, it's really just to point out we have a number of supplemental slides in the back for your review. We're not going to cover those for today, but wanted to point those out. So that really concludes my remarks. So, Pam will go ahead and open up the call for

Thank you. (OPERATOR INSTRUCTIONS). And our first question comes from David Kistler with Simmons & Company.

Good morning, guys.

Hey David. Do you have a question, David?

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

Can you hear me?

No, -- we heard you then. We didn't hear you before.

I'm so sorry. A quick question for you guys with respect to being able to maintain production guidance at kind of a 5% to 10% with the large CapEx cut obviously highlights low decline assets. Can you break down what portion of that you expect to be oil, what portion you expect to be gas, and maybe associated declines with both of those?

Yes. I think we have a slide in the back in the appendix that goes over all of the reasons why we can do that. But obviously you've got South Africa that's 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're producing gas, and Alaska is growing -- its oil. Spraberry is still growing, and then you have Raton, that's more flattish. Edwards, a slight increase with our -- we have still, as Tim mentioned, several gaps and shut-ins that we'll be bringing on here in the next month or two. And then you have, oh, I think about a thousand barrels a day from VPP volumes that's coming back. That's primarily --

Gas and oil combination --

A combination of both, so --

Okay. That's --

It's probably -- your oil 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.

Great. Thank you. Thanks for taking the time on that. And then kind of going to the rigs, the 17 rigs that you're letting go. What portion of those were under contract on a term basis, you know, as a result of your incurring that charge? And then, of your remaining 11, are those all currently on term as well?

Yes. The rigs that we're looking at terminating, they all had very favorable termination charges. The termination charges were at 30% to 40%, all of the current day rate. So that's one of the reasons we looked at. We get a very favorable termination charge. It's much -- if we -- that's why we're terminating. So we're not going to bring any of the rigs back for at least six months or longer. Probably six to 12 months. Because we think it will take that long from the service call. So basically, about three contractors that had very favorable termination charges is why we're terminating those contracts. Most of the contracts ran out primarily by the end of 2009.

Okay.

The rigs that we're keeping, most of them run out next summer. We're getting much more positive feedback in regard to immediate cost reductions.

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 flow through?

No, no effects with transportation agreements at all.

Okay. Great. That's very helpful. I'll let someone else jump on.

Thank you.

Next we have Michael Jacobs from Tudor, Pickering, Holt & company.

Good morning, everyone.

Hey, Mark.

Starting off kind of with the CapEx, I'm trying to reconcile the 500 million to 600 million in annual CapEx to keep production flat post-2010 with the $200 million that maintains flat production over the next two years. Just kind of thinking, using '09 as an analog and thinking about your in the bag growth of 7,000 to 8,000 barrels a day from Alaska, South Africa, south Edwards. Does that say that base company declines by 7,000 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 to 8,000 barrels at $300 million to $400 million? Is that the right way to think about it?

Yes, it's close. The purpose of the $200 million -- obviously we don't think that we're going to see $60 and $6 for the next two years. The purpose of it is we can get down to $200 million, and there's a slide in the appendix, that gives it -- the detail and the backup to that, that we could spend $200 million in '09 and '010 and keep production flat. By obviously only spending another $300 million, and that $200 million, by the way is primarily continuing to drill in Alaska.

Okay.

It's about $125 million of the $200 million. There's lease bonuses in there to maintain leases in a worst case scenario. So for another $300 million, we can basically add roughly about 5% production growth.

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

Yes. Nothing has changed. We've been drilling Spraberry wells for -- we drilled 5,500 wells. We have another 20,000 wells to drill. The wells have gotten better since I've been associated with the Spraberry these past 30 years. We're still highly encouraged, about 20-acre spacing. We're highly encouraged, still moving forward on the waterflood as Tim mentioned. Additional oil from the pay zones, but also -- and we're getting a bigger acreage position in the Wolfberry. We'll be drilling several [Graybergs] and [Andreas] prospects. We're getting shows as we drill through those in the Spraberry Trend area in 2009.. The only thing that's changed, we just don't feel like in this environment, a 20% return at current well cost to $1.4 million is worth drilling, running 17 to 20 rigs. So we've got to get the costs down. If we can get the costs down, we're probably over time going to look at owning more and more of our own equipment. It's worked in Raton to keep costs in check. Probably be looking at that seriously. We talked about moving the frac crew down to keep costs down, because we've got to keep the machine running. If it wasn't for the sudden collapse, we would would not have reduced the rig count. So it's still a great asset, and we're still going to move forward. It will be the drive engine for the Company, and the reserve booking for the Company over the next 10 years.

And just to add a commentary, I would say this has absolutely nothing to do with asset quality. As Scott alluded to, this is a manufacturing process for us. We've got, you know, 890,000 acres out there. Most of it's HVP. We don't have to drill these wells. There's no sense in a manufacturing analog, making widgets when we're not making the kind of returns when we can lay these rigs down, get costs down, get back to margins that make sense. In fact, it's the opposite of what you said. I think the assets are proving to be the highest quality oil on-shore assets that are out there.

Scott and Tim, that makes sense, and everything you're saying, you know, makes a lot of sense. But just the make sure I understand the CapEx cuts, and I recognize you haven't finalized an '09 budget and recognizing that you'd rather buy stock than spend capital that doesn't meet your hurdle rate, all of that makes a lot of sense. And the release in presentation lets your service providers know how serious you are. Have you gotten any initial reactions from primary drilling work over completion service providers. Have they contacted you once you put the information out there? Or is it just too soon?

Yes. We've gotten all kinds of reactions, ranging from we're not going to cut it at all, to we're cutting at 20% to 25%. So it all depends on who you talk to, how big the company is, what their backlog is. Like pumping service companies generally, they're -- there is such a shortage of wells to be fractured in the on shore US., that it's going to take a longer time frame for them, the rig count to come down, for those costs 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 to 45 days. So you'd think we'd get a 30% reduction. In our tubulars, we've only gotten an 8% reduction. We've been told it will take another three to five to six months before it all filters through. So those are examples. Polling unit companies. Some have already dropped 25% to 30% on per hour. Some of the ones that we're using. So those are some of the examples.

Yes. That (inaudible) is proactive, too. We're not waiting on people coming to us. We're going to them, Michael. So those meetings, several have been undertaken and more as well. We'll be going ahead.

That's great color. I really appreciate that. Just one final question. For those of us who, you know, 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 termination costs and recoup those lower costs going forward? And, how much do day rates need to drop to justify that expenditure?

Yes. The $40 million to $45 million was about 30% to 40% Poff the current day rate. Okay. The decision we had the make, do we -- do we overspend the next six, seven, eight months pushing the growth profile? We could have announced a 12% to 14% production growth file. Right now the strip for 2009 is about -- it's moved up obviously in the last two or three days, it's moved up to roughly $75 and $7.70. It got as low at $6.80, and roughly about $67 recently. So we're still very pessimistic that the commodity price, first of all, is in contango and move forward. I don't see enough rigs shutting down to drive down the big potential gas -- storage and gas supply issue until people get 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 had -- the choice was, do we hedge 100% of our commodity at $7.70 and $75? We decided not to do that at this point in time. We think there's more upside. We will get aggressive on hedging if we see it. Get up into the $88 range or higher, and bring in more cash flow. Those are the choices we had. So we did not want the go into a big overspend overspending cash-flow mode over the next six, seven, eight months.

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

Exactly.

Great. Sorry, guys for the long questions.

And next we have a question from Gil Yang from Citi.

Just a point of clarification first. On page six, when you give the returns and the price at the various prices, those are unhedged prices, is that right?

That's right, Gil. It's flat for the 60 years of life for the Spraberry well.

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

Yes. We are on a plan, as you know, to ramp up to 30 rig, which is in our prior presentations, or about 700 wells per year, I think about 2011. Obviously with what's happened with commodity price downturn. We've got to take a different view. In other words in the future, what do 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 probably tend to own more and more of our own equipment. We're probably going do some more hedging or buy-in puts as we see prices. So we don't go through ramping up to 20 rigs, back down to seven, back up to 20, 25 and 30. So we're going to put more protection [rings and bites] on more equipment to get the inventory drilled, and we'd like to get up to a thousand wells per year at some point in time, is the goal.

We already drilled the wells 20% to 30% less than the competition.

Okay.

That's really what we've accomplished over the last several years.

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

You know, the two big improvements that we have made is the silt shale intervals, where we're adding additional reserves and production through early testing. And second by going deeper into the Wolfcamp, we're making much better wells with a fairly -- with a $10 fining cost at yesterday's cost, which will go down. We're adding the Wolf cam and making much better wells. That's been the biggest positive in regard to a typical Spraberry dean well, is adding the more shale, silt shale and adding more Wolfcamp, we're getting more reserves and higher production rates.

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

The first well, I mentioned this in my comments has done exceeding well. Very flat production. At any given day, 45 to 50 barrels a day. And that's producing only as I mentioned only from one of the non-traditional zones in the well. We're planning now to move to produce another non-traditional zone, up the hole and then furthermore one of the more traditional zones to get a feel what's the contribution from each? The second well will be the target of completion. We have not yet completed the second well.

Okay. And so the flat production curve is different from the normal Spraberry sand well?

Yes, I think it's a case that we are positively surprised by the fact this well has been relatively level in production. Looking at our tight curve, it's not unusual to expect reasonable declines in the first several months or year in production. So we've definitely been, you know, encouraged to see that result.

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

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

And so for the one well producing 45 to 50 a day, how many intervals are they producing on us?

I'll have to get back to you on that. I don't know exactly what number of feet we have completed it in. Can we get back to you on that, Gil?

Sure. But it's a fraction of the 30, right?

Yes. It's one particular non-traditional zone. I don't know how many exact intervals of the traditional zone. Several different intervals, but they're all non-traditional. I have to get back to you on that.

Okay. Thanks.

Next, we have Joe Allman with JPMorgan.

Yes. Hi everybody.

Hey Jeff.

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 fixs?

Yes. The first fix obviously, we're evaluating on whether or not to go in and hedge aggressively the basis differentials over the next several years. The basis differentials go down substantially over the next five years. So that's the first thing we're doing at a company level. The second thing is, we need cold weather short term. And we need the 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.

Okay. So you think -- so, you know, you think it's just too much production, the Rocky Express. How much do you think the problems with the processing plants has been a part of the wide differentials?

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

Okay. And then terms of your planned cuts, when you're looking at economics are you assuming that we're going to keep these wide differentials, or do you kind of normalize the differentials when you're making your decisions about dropping rigs.

We're assuming we have to make a decision whether or not to hedge aggressively differentials, as some companies have done recently, as we start back the rigs. It will probably be in tandem. We'll be hedging aggressively, differentials only. Maybe not the NYMEX price. And at the same time once we do that, after that, we'll be bringing some rigs back.

Okay. So.

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

So when you're looking at the economic -- if you're looking at the economics right now and you're using whatever -- the price of the strip or whatever, you're assuming that there is a greater than normal differential for whatever, the next 12 months or so?

Short term. Short term. Maybe the next six months or so for sure.

Okay. Great. Very helpful.

We have a question from Leo Mariani with RBC Capital.

Yes. A quick follow-up on the Spraberry here. Obviously you talked about getting some additional production contribution out of your silt and shale zones down there in Spraberry. What would be the incremental costs to bring that on if you guys were to co-mingle it with some of the more traditional zones?

Yes. Very little. Probably $40,000, which would be in addition the frac job. So almost insignificant.

Great. Kay. In terms of the second wall here, sounds like you folks are planning on doing that. You're going to have results in the next couple of months, announce it if you get something?

Yes. But I'm hoping it will probably -- come in the same 45, 50 barrels a day and just sort of stay flat. So that's what we hope happens, instead of going on an immediate decline.

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

Leo, we are going have to drill some new wells in the waterflooded area to make sure we have it fully 40-acre drilled. So you will have the normal drilling economics. Hopefully they'll improve as we've been talking about as we drill the wells to complete the 40-acre pattern. The other thing we'll do is drill the injection wells, and in some cases we'll be converting current producers to injectors. In the economics or something like this, if we're based on current costs, not necessarily where they may go, but we'll be converting a current producer into an injector at the rate of somewhere between a $100,000 and $200,000. And to the extent we need to drill a new injector based on old costs where a well would cost typically $1.4 million. It might be a $1 million in the old cost regime to drill, you know, the injectors. So we'll probably be, as I said, doing a combination of those exercises. The economics are excellent, though, because at the same time we're -- that we have now -- be introducing water in the system, what we're in effect doing is injecting produced water, which reduced our LOE, reduces our water handling, our need to truck water out of the areas and so on. So there's an LOE benefit you have to put in the equations as well. Overall, we have seen empirically that we tend to get a pretty rapid bump in production say, six months after introduction of the water to the tune of sometimes 2X to 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 meetings and other investors, we're looking at probably for every barrel that 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's not that costly to put that in place.

Got you. In terms of your gulf Mexico shale production, I think you guys still have around 2,000 barrels a day. Any update as to when that may return at this point?

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

Okay. So I guess just final question for you guys here, in terms of what production you have on the gas side it's not subject to mid-continent pricing, is that basically your off-shore and Edwards trend?

Nothing really. Very insignificant offshore, and Edwards Trend is the only other gas. Even though Houston Ship Channel has blown out to -- historically it's $0.10 to $0.30 cents it's blown now October, November to $0.75 cents.

Okay. So --

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

Okay. Thanks for your time.

Thanks, Leo.

And next, we have Rehan Rashid with FBR Capital Markets.

Afternoon, Scott.

Hey, Rehan.

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

Yes. After taxes it's about a 12%, 13%, 14% return. When you run it through the balance sheet, it's not a return that we think is worth drilling to get a 20% return. So that's why we historically have always tried to achieve a minimum of 40%.

Right.

And that's -- we feel like we'll get there.

Got it. Got it. In terms of the costs, $1.4 million to drill a Spraberry well. Rough break-down as to how much is drilling, how much is completion and whatever else there might be?

Drillings about 15% to 20%. A 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 be miscellaneous, such as, you know, the pumping unit will be your next biggest item. It's probably 3% to 4%. So there's a bunch of items in the 2%, 3%, 4,% range.

So of the total cost maybe only 20% shows some amount of stickiness, and the rest shows a trend down.

They're all going to show a trend down. We've had -- one of the primary reasons we're keeping several rigs running. We've had tremendous negotiations with certain drilling contractors and not with others.

Got it.

Okay. So we've seen significant decreases already in drilling contract rates, with certain drilling contractors, not with others.

All right.

Pumping services will take slower come down. Tubulars, as I mentioned earlier, will come down slowly. We've gotten 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.

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

Yes. Raton is very similar, 20% to 22% at $6 flat gas. That's used in -- because we have our own equipment there. The primary reason we're stopping there is simply because of the wide differentials.

Got it.

The horizontal Pierre and the brook Pierre as Tim said. The vertical Pierres are doing much better, the last few wells than expected due to new stimulation techniques. But again, it's back to the differentials.

Got it.

We have to make a corporate decision as to whether or not to aggressively lock in differentials over the next several years.

As you -- as you think about reramping your CapEx, is there any particular order in terms of projects that you would go for first with the mix being kind of the same as it has been?

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

Got it. One last question. Stock buyback, when can you resume? What's your remaining authorization? Are there any restrictive covenants that would allow you to buy back as much as much as you want to? Yes, there is 450 million left out of our 750 million program. We can start back 48 hours after today. Got it. Got it okay. And what was the average purchase price of the 2 million that you bought so far?

Two million was primarily third quarter, around $50.

Oh, okay. All right. Thank you.

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

Thanks a lot. 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 as the production of demand, you know, utilizing more Barnett gas, less mid-continent gas? Any thoughts on that? That's the first question.

Yes. Monroe, I addressed it earlier, but I just -- it's not just mid-continent area. Mid-continent, the first trunk of the Rockies Express line goes into Missouri so all of the pipes go through from Missouri through mid-continent. So mid-continent and Rockies gas all go to the same place, and it can't get out. It can go Chicago, but it can't get into the feathered northeast markets.

Right.

Until Rockies Express, the second expansion happens. It was delayed. Permian -- of all areas, we are seeing Barnett shale -- half of the Barnett shale is experiencing $300 to $350 differentials now. Most of it's -- a lot of it is priced off of Waha. Waha is getting $300 to $350 less. Houston Ship Channel is getting 75% less. To me there's too much gas in the system. Storage is essentially full. There's too much gas in the system. We've got too many rigs running.

O kay.

So gas on gas competition. So it's not just mid-continent Rockies now. It is all over.

And I'm sorry I missed your comment from earlier. I got on the call late.

Yes.

Second question was, when you look at your -- if the members of the credit facility you have and all the lenders that are involved there, I guess two questions. How often do they review -- do they review the credit facility, and when's the next review due, and do you have some concerns that any of these people in your bank lines are under some pressure because of the other parts of the banking system are having problems, they're under some pressure to reduce their exposure to the oil industry?

[Ammon Northridge]. We don't have a review requirement in the current facility, it's good through 2012, as we mentioned earlier. 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 in our credit facility, you know, today, I'm not -- any big concerns about any of them. Obviously the banks have been less in the headlines for the last couple of weeks. So hopefully that bodes well that things are improving on that front. I think, on the other side, in terms of where we go from here -- I mean, some of those banks wanted to reduce their exposure. Some have moved some exposure over the last couple of months into other banks. We had other banks that have come in and picked up at capacity. So I really, today, think everything is fine and don't expect any problems. That's not to say they can't happen, but I think things are improving.

Hey. Thanks for your comments.

Monroe, one other comment is that the -- in discussion with some of the banks, people who have reserve based lending.

Right.

Versus unsecured, the banks are going to be most likely using a $45 price deck.

Interesting.

So that's coming up in the next -- by end of the year, and so that's going be the next shoe to drop. We're unsecured. We don't have a borrowing base, but obviously those that have borrowing base it's a bigger issue.

Right. Do you know what gas price they might be using?

They will take about 70% of strip pricing, so closer to $5 probably.

Okay. That will create some problems for some of these people, I would say?

Yes. So hopefully will see some more rigs drop.

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

Okay.

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

Okay. Again. Thanks. Appreciate everyone's questions, and again, we've got great confidence in our assets, and we're going to resume this growth profile, but we think it's more important to do some other things, be prudent, be very prudent with capital over the next six to nine months. Look forward to the next quarter call in February. Thank you.

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