先鋒自然資源 (PXD) 2006 Q3 法說會逐字稿

Good day ladies and gentlemen, and welcome to Pioneer Natural Resources third quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer, Rich Dealy, Executive Vice President and Chief Financial Officer; as well as Frank Hopkins, Vice President of Investor Relations. Pioneer has prepared a Power Point slide to supplement their comments today. These slides can be accessed over the internet at www.PXD.com Again the internet site to access the slides related to today's call is www.PXD.com. At the web site select investor, then investor presentations.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions and 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 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 am pleased to turn the conference over to Pioneer's Vice President of Investor Relations, Mr. Frank Hopkins. Mr. Hopkins, you may begin, sir.

Good afternoon, everyone. And thank you very much for joining us. I would first like to apologize for any inconvenience that we may have caused by rescheduling our call today from 9:00 a.m. to noon central time. Unfortunately we just learned yesterday that other E&P companies had scheduled their calls at the same time as ours. So to avoid conflicts we changed our start time.

Next let me briefly review the agenda for this afternoon's call. Scott Sheffield will be the first speaker. He will discuss the highlights of the third quarter 2006 for Pioneer. He'll also update you on key operational initiatives and how the company is progressing towards achieving its production growth goals for 2006 and beyond. After Scott concludes his remarks, Tim Dove will report on how each of our assets is performing against its 2006 production and operating goals. You may recall that we committed to provide this quarterly update back in March at our analyst's meeting.

Tim will also bring you up to date on our successful exploration activities in the south Texas Edwards trend. Rich Dealy will then cover the financial highlights from the third quarter and provide earnings guidance for the fourth quarter. After that we'll open the call up for questions. With that, I'll turn the call over to Scott Sheffield.

Thanks, Frank. And good afternoon on the East Coast and good morning on the West Coast. We're on slide number three on the highlights. We reported net income of $81 million or $.64 per share. In addition, third quarter production of 99,000 barrels of oil equivalent per day. I think the most important message with -- with our production growth this year is the fact that north America production is up 14% year-to-date.

We gave out guidance the first part of the year, we're going to end up around 36 million BOEs equivalent in 2006 as with our fourth quarter guidance number. So obviously we're very pleased with that. 2007 will continue with that North American production growth coupled with the fact that South Coast Gas and our Tunisia growth will be significant and coupling -- bringing -- bringing those two together obviously we're very excited about continuing to deliver on production growth over the next several years. We continue to buy back our stock during the quarter, bought back 3.1 million shares at a price a little bit below $40. We have a longer -- long-term goal to continue to reduce shares. We have taken the share account down from about 150 million shares down to about 120 million shares over the past two years. We have a long-term goal the next four to five years to take it on down to roughly about 100 million shares.

We'll consider additional obviously repurchases to complete that once we complete this program. Also in the early part of the quarter with having a lot of flush production coming from our gas drilling in 2007 we decided to go ahead and hedge over $90 million a day at over $9 NYMEX. Rich will go over the exact schedule in back to help protect the economics of our 2007 drilling program.

We ended the quarter net debt-tobook of about 27%. Strong improvement from our year-end 2005 of close to about 48 to 50%. Still confident targeting 10% per share production growth in 2007. That's based on obviously the current strip prices as of today somewhere between $7.50 and $8 gas, and also between 60, $65 crude for next year. Our 2007 capital budget obviously will be more closely in line with expected DCF, which will in regard to a number we'll see a 20 to 30% reduction from the capital budget of 2006.

Turning to activity, regard to our growth opportunities on -- on page number four, in Alaska, Oooguruk is still on schedule. First production expected in early 2008. We are commencing sometime the early part of the year 2007 a two well NPRA drilling program with Conoco-Phillips and we also plan to be testing our on Cosmopolitan Discovery sometime during 2007. Shale gas, we are commencing several tests as we have mentioned last quarter.

We'll have news out early next year of several plays near existing core assets in both in Texas and the Rockies. In the Rockies, we are continuing a very aggressive drilling program in Raton. We're seeing production rates obviously much better than we expected, Tim will go over more details there. We continue to produce gas in de-watering in several of our CBM pilots. And we began a rig in drilling three Entrada Dakota type gas wells, which we just started, and we'll report on that sometime in January or February of next year.

In Canada, continuing our aggressive Horseshoe Canyon drilling program, I think the important message there is we have many wells to be brought on production, they'll be brought on here later this and early this year. In Permian continuing the aggressive -- which has been our biggest growth driver. In the Permian, primarily Spraberry drilling program continues to add additional acreage and bolt on acquisitions there since we're the dominant player in that area. Continue to have success, had another discovery in the Edwards Trend. We are shooting 850 square miles of 3-D seismic over all of our discoveries through 2007 and continuing will be adding acreage and bolt on acquisitions there.

The Gulf Coast, we have two wells going down in Mississippi. The Norphlet test will be down sometime in December. We'll make comments on that. Obviously that's in our dry hole costs which Rich will talk about. We're drilling a series of Cotton Valley test wells, primarily more development oriented in the fourth quarter and also the first quarter of 2007. Our second appraisal well was successful. We did find more pay, we found 120 feet of gas pay. So we are obviously in another fault block by finding gas.

If you recall in the discovery well in addition to the first appraisal well we found oil. We had 30% porosity. And secondly our Flying Cloud prospect was unsuccessful. So this will put us at the lower end of our previously announced guidance on our Clipper Discovery of about 25 to 50 million BOEs equivalent. Still expected to come on in 2009, or at late 2009. We're still talking to three or four post facilities that we'll be tieing into obviously by getting more gassy.

That's a plus even though it's reduced to size of the target by finding gas. Obviously it does improve the economics by finding gas and gives us more options in regard to the tie-in facilities. We are evaluating our bids on our shelf property as we mentioned earlier we were marketing them, we're evaluating those bids now. Hopefully announce something later this year, early part of 2007.

Slide number five. Africa growth opportunities really a -- next two quarters very critical for Tunisia. We had a very successful appraisal well in Hawa It's our third well will be coming on line later this year. And then we're drilling five very important wells. They are all on 3-D seismic recently acquired on three concessions. Pioneer will be drilling three of these wells along with two by ENI.

West Africa, we are pursuing options to reduce our interest in our three well drilling program in '07 and '08. I hope to have something announced later this year, early next year on that. And then in South Africa, that project is on schedule expected to come on the second half of 2007. As I mentioned earlier on the first slide we do expect significant growth in South Africa especially with the South Coast gas project and also with continued Tunisia success in 2007 and 2008.

Slide number six, obviously, since the last call we've had a significant reduction in the strip of oil and gas. This slide shows you obviously at two different price cases, a sensitivity case, and another price fairly close to the current strip, $60 oil and $7.50 gas, flat, $50 oil and $5.50 gas. Obviously we're -- we're seeing very strong returns at both levels in all of our key development areas. We've had this slide out the last couple of months. But it's just emphasizing the strong returns we're continuing to see in all of our development activities.

Let me now turn it over to Tim, to talk about our production growth.

Thank you, Scott. As Scott has already mentioned, we have continued to make solid operational progress in the third quarter. And as shown on slide seven, production has continued to ramp up mostly because of development drilling in some of our key areas, such as Spraberry, Raton, and Horseshoe Canyon, as Scott has already gone through. Very pleased to show that production over the nine-month period in 2006 in North America is up about 14% compared to the same period in 2005 on a pro forma basis at about 93,000 BOE per day.

We currently have 39 rigs working in the quarter. That's up substantially from year-end numbers. And we're well prepared to embark upon an aggressive drilling program in 2007, and have all the rigs available to do so. Importantly, our North American production growth is -- is on target to meet our exit rates that were defined in March and be at the high end of that range with about 95,000 BOE per day. And toward that end, the total Company production, including African production, is expected to range in the fourth quarter between 98,000 and 103,000 BOE per day.

Turning to slide eight, Spraberry continues to provide a growth foundation for us in terms of the development drilling that's been done in that field. In the nine-month period in '06, production is up an impressive 23% compared to the same nine-month period again on a pro forma basis with last year. Our drilling program is essentially on track. We've drilled about 240 wells through October. We've been ramping up the rig count of course though the year where we now have about 20 rigs operating in the basin. And we'll be very close to our year-end target we -- we established a target of 335 wells for the year. We'll be close to that as we hit the end of the year.

Importantly also we have been drilling several of these wells deeper for Wolfcamp opportunities. And we've also been successful on smaller bolt-on acquisitions that have added to Spraberry performance with very positive economics. Now we have continued to, as we've been talking about several quarters in a row, add peripheral and infill acreage to the point now, this year, we've added over 90,000 gross acres in the Trend.. So there still are opportunities out there to add acreage and in doing so add -- add reserves.

One thing that's not identified in the slide but nonetheless is important to us is we continue to look at efforts to control costs. Recently we found an opportunity to expand our integrated services model. The same thing that has worked so well for us in Raton by purchasing 14 pulling units. These of course are used for the completions in workovers in the field. And having done so, we should see a substantial savings in LOE, perhaps up to $7 million per year looking forward.

So we're very pleased about that transaction and believe it can be a contributor to reduce cost as we look ahead. We also are being open-minded about how to -- how to provide services and equipment for the field. We, generally speaking, in 2006 and 2007 are heading more towards using Chinese tubulars, which are cheaper but are non-theless of very high quality. As well we're using a great deal of Chinese pumping units. All of these have worked extremely well for us and have given us an opportunity to reduce costs in the field.

Turning to slide nine, in the mid continent, we've done an excellent job in these two fields, that's WestPan and Hugoton, of maintaining production. It's basic blocking and tackling, something we're really good here at Pioneer. The result of which is shown here, production has been essentially flat throughout the year. That's a very -- very positive statement given the fact we aren't drilling very many wells out in these areas. The reason for that is pretty clear.

We -- we've been able to exceed our projections in terms of performance, mostly because of doing a lot of well cleanouts. We've implemented significant SCADA systems in the field for field optimization and which reduces down time. And we've been electrifying compression in the field to reduce costs. The bottom line is we should substantially exceed the March forecast we had for the field, in that we've been able to keep production essentially flat so far this year.

On page ten in referencing Raton, we're very pleased with the results from this key CBM field for Pioneer. You can see that our production has continued to ramp up. It appears very clear now we'll be able to exceed both our longer term growth target which had been 5% to 7% as in 2006 compared to '05. And our exit rate, you can see were production today, in the third quarter anyway, is essentially significantly above even the exit rate that was forecasted in March. Production is up about 9% for the nine-month period compared to the same nine months in '05.

So it's been very good results from Raton. We have increased our rig count by a rig so as to be able to complete our program. Actually, next year we'll probably be drilling two rigs in the beginning part of the year and we're gong towards Pioneer -- Pioneer owned and operated rigs in the field. Again going further towards that integrated services model that's worked so well in the Raton field. We've drilled about 250 wells though October. We expect to get very close to the target number which is in excess of 300 wells by the end of the year.

The key to the production having been so successful in this field is diligence and very close inspection of what needs to be done to maintain the pipeline capacity and actually doing a lot of work in terms of compression in order to increase production in addition to the drilling program. And doing -- this is a wellhead compression additions and so on have been extremely successful in the field.

On page 11 and 12, actually the next two slides cover our Edwards Trend area. Of course we're very excited about how -- how this trend development is going. And in fact, I think we can say today we're still very optimistic about what the future holds for Pioneer in this area. On slide 11 as expected our net gas production from the total Trend in the third quarter was about 38 million a day, which is essentially flat compared to the first half of this year and about the same as the nine-month period last year.

The reason for that is, of course, most of the current production still comes from our existing field, the Pawnee field where we have not been doing much development drilling so far this year on the basis that a lot of the drilling we've been doing has been exploratory in the Trend. That is we've been taking rigs away from the development drilling campaign and extending our Trend acreage discoveries. We will also be limiting our development drilling in Pawnee in the fourth quarter with the idea of continuing to focus on those exploration activities. However, we do expect to see the overall trend production increase by year end. We will, we believe, meet our forecast exit rate from the March meeting as we continue to tie in some of our recent successful wells from our drilling campaign.

Turning to slide 12, here we highlight our results from our exploration and appraisal activities during the third quarter and then also what we've planned in terms of the remainder of 2006 and for 2007. We're extremely excited about how our results have come out so far in this resource play. We really do believe this continues to hold substantial reserve and production growth potential for the Company looking ahead. The expansion program, we would say, is on schedule today. At this relatively early stage of the program and given the fact there's really limited infrastructure in and along this Trend, today we really measure success in terms of the discoveries we've made as opposed to current production, from the wells that are on production. On that basis we feel very good.

By this time next year, of course, we expect to be measuring success in terms of a significant growth in production from the overall Trend. As we've already said in the past, we have been adding acreage, we now are up to almost .25 million acres along this small bandwidth of land that extends 250 miles through the state of Texas. We did add a new discovery to the find that we've already made this year, bringing our total to six discoveries for 2006. These are new Trend discoveries in the Edwards area.

Of course before these wells have been put on production, we have to put gas processing facilities and install those along the trend. This Edwards gas does have a small component of H2S, so we must put in place portable amine units. To extract that H2S, and therefore at that point in time they can be connected back into -- into our facilities. In some cases, we're going to have existing facilities away from our Pawnee processing plant that will be independent of Pawnee. Some of this gas will hopefully be tied also back into our existing Pawnee Plant.

We did have two of these portable units during the third quarter. That means now we have a total of four in the Trend in addition to our large Pawnee processing facility. Longer term, really as I said we really want to move as much of the gas as we can into our Pawnee facility and process it there. That will allow us to hook up our wells faster and make the gas trading much more economical then scattered portable units, By the end of this year, we expect to have a total of 23 exploration and appraisal wells drilled this year associated with the expansion program. And 17 of those wells were -- had had spud by the end of the third quarter. But only five of them have been hooked up.

And so we're now producing a relatively small amount of gas, 6 million on the basis that we only today have five wells hooked up.. But the important point is that we have about 12 wells remaining that are either currently drilling or are awaiting pipeline or are testing. When these wells come on, of course, they are going to have a significant impact on the growth for the area. Two of those 12 wells which individually tested at initial rates cubic feet per day initially tested about 3.5 million cubic feet a day. Those will be tied and hopefully within the next few days. And so we should start seeing impact from those wells pretty -- pretty clearly, shortly.

In total, we plan to drill about six wells in the fourth quarter. That would include one new field prospect and five appraisal wells on existing discoveries. We have about five rigs in the field today and expect the sixth rig to arrive early next year. We have all the available rigs needed to make this appraisal program and development come off.

Based on our drilling to date and our appraisal of those successes we've had, we now believe that we have confidence in saying that we've established a resource potential in the area, in the trend of about 150 BCF to 325 BCF. The way I would characterize that is 150 BCF would be a P 90 number, 90% probability, and then 325 BCF will be more of a mean number. But that is only based on the drilling we've done to date. We try to be conservative in these numbers. We continue to see these numbers grow as the exploration program moves along the Trend and we continue to add new discoveries.

Of course, our Pawnee experience tells us that 3-D seismic is very critical to locate the wells properly, these are the development wells. And orient these horizontal wells, which is typically what we use in development for -- to optimize production. Today it's the case that there's only a limited amount of 3-D that's been shot along the Trend. We bought every -- all the 3-D that's available on the trend. But we are going to need to shoot new 3-D along the trends in the areas where it is not currently existing. And then, of course after shooting this 3-D they are going to have to be interpreted and then we have to then get out and decide how to orient the development wells.

But some of these areas along the South Texas trend area, it can take several months to actually get all this done, 9 to 12 months perhaps as we have significant permitting requirements. We need to get l landowner approvals and we have limited access during hunting season, which is coming up. So we do need about 850 square miles of new 3-D and it's gong to take us some time to get that shot and that will have a tendency then to -- to move the development program into next year. We are going to plan several surveys in 2007 to acquire all this seismic. And we're, today out there permitting the new shoots and working with landowners toward that end.

We do -- we do expect to have most of this done in mid next year, mid 2007. At that time we'll really launch a more aggressive development campaign then we'd be willing to do today. In other words we want to have confidence we're -- we're spotting these wells in the right -- in the right spots, in the right -- be the right configuration. And if we -- if we chart ahead where we think we can be by the end of next year, we think we can increase production from the Trend by 50% or more by current rates by virtue of that development campaign.

We'll also continue to drill the new field prospects, the exploration prospects along the Trend and plan about 10 for next year. We'll drill most of those probably in the first half of the year. The bottom line for the Edwards is it's been a success to date, a great success, we feel. And as that success continues, we think it's going to start having a more significant impact on more measurable parameters. But today I feel like we're on schedule and the trend development is going exceedingly well.

Turning to slide 13. Canada continues to show a continued ramp-up in production. You see the third quarter numbers of about 51 million cubic feet a day. Today it's about 54 so we continue to see a march towards meeting that exited forecast rate which is plus or minus about 60 million cubic feet per day equivalent. Production in the third quarter was up about -- about 15% for the first half of the year. And importantly up about 16% when you compare this last nine months to the nine months of 2005.

We have rigs out there drilling our Horseshoe Canyon program. Scott already alluded to this. Three rigs out drilling right now. Last December we had five rigs running to complete the program. There are rigs available in Canada if we wanted to add a rig or two to get this program done. We feel pretty confident we're going to complete our program this year. It'll be right at the very end of 2006. We are adding additional compression which is needed of course in the area as we tie in these wells. We have compression being added in three areas in the fourth quarter to tie in all these new wells. So Canada is going well. And we should, as I said, expect to meet that exit rate that we put out in March for our combined field operations up north.

Slide 14 refers to African production. Of course, South Africa and Tunisia oil. We have seen a slight decline the third quarter, as expected. And anticipate that the fourth quarter production would be essentially flat, meaning that we will meet that 2006 exit rate that approximates about 6,000 BOE per day. Sable oil field there in South Africa offshore has done as -- done very well. Exceeded expectations in terms of performance. And the Adam concession has been essentially flat throughout 2006. Importantly, we have drilled the successful appraisal well Scott mentioned it should be on production here in the latter part of the quarter. And we would expect ranges of well on a gross basis of 2 to 2.5 thousand barrels per day. So it could have some substantial impact. The key to Tunisia is of course ramping up the drilling program. We'll continue to do that as we get into 2007. And as Scott mentioned, South Coast gas is a project which is going to be significant in terms of its current growth, that is second half of 2007. It has potential for further growth I'll mention in a subsequent slide.

On slide 15, Tunisia, Tunisia of course is something we're continuing to work on growing. We've been very successful drilling wells. We've drilled nine successful wells in the Adam concession now when you consider the Hawa appraisal well, and as I mentioned that should be on production here shortly. We have five wells total to be drilled in the next few months. Four will be drilled in the fourth quarter including one on Adam, two on our operating block Jenein Nord. We've brought over a rig from the U.S. to begin those -- drilling one of those wells is going down as we speak. And another well in the southern area called Borj el Khadra.

One thing that's happened in this area is we are beginning to increase gas sales. The block currently here, I'm speaking of Adam produces about -- Or sells about 8 million cubic feet a day of gas We think that can increase to up to 21 million cubic feet a day by the second half of 2007 as a pipeline expansion is under way. And so I think this area -- the note here is this area does have gas potential, and I think we can grow some -- a grass -- a gas business based on these southern Tunisia assets.

Slide 16 is a review of our two key development projects. These are both essentially on schedule and on budget. Of course, we've also mentioned South Coast Gas. We've -- we're still in the process of completing the development drilling campaign that should be done by the end of the quarter or so. We'll have an All Seas pipe vessel out there to lay any pipe and umbilicals during January with first production still scheduled for second half of '07. This contract of course only goes really roughly to 2012. We think this area has substantial potential after 2012 for uncontracted gas. As you can see on slide 16, we call that over 200 BCF of additional gross resource potential after we finish with the existing contract.

On the Alaska front, happy to have completed our gravel drill site on schedule. Of course, as you see in the photo, we're heading towards winter. I mean you already have ice out there, a thin sheen of ice as we start towards the colder weather up on the north slope. Of course what's happening right now is we're waiting on the winter construction period. It's coming pretty quickly at us.

We should be out building ice roads somewhere in the neighborhood in the mid part of December. And then the idea is to be out there fabricating production modules and putting them in place all through the first quarter. Also installing the sub-sea pipeline back to the shore for the production and installing the rig. We need to get the rig out there before ice moves out, which would be sometime at the end of the winter, of course, March or April. And then drilling would commence in latter part of next year. First production still on schedule for 2008.

The Oooguruk in and of itself has substantial up side. But we know that there's known reserves in and around Oooguruk that we're now evaluating for potential tie-ins as we get closer to actual production out here. In fact we know there's a known resource about two to three miles away that's 20 to 30 million-barrels which has several wells already having penetrated it. We also see an upside here. Especially now that we've established kind of a foundation for our production in the north slope.

And with that, I'll pass it to Rich for review of the financials and -- on the third quarter and review of the fourth.

Great, thanks Tim. Turning to slide 17 for a third quarter revue of the highlights as Scott mentioned net income was $81 million or $0.64 per diluted share. Operating cash flow for the quarter was $183 million. Discretionary cash flow $225 million. We exited the quarter with net debt of $1.1 billion. That was comprised of 1.2 billion of the carrying value of our senior notes, offset by $100 million of cash on the balance sheet. Also it's important to note that our $1.5 million credit facility had zero drawn at quarter end. Net debt to book capitalization was 27%, and then for the quarter we had costs incurred of $406 million bringing our year-to-date total at just over $1 billion.

Turning to slide 18 for a discussion of our realized commodity prices, you'll see that our commodity price realizations include the effects of hedging and deferred revenue amortization associated with our VPPs. As I mentioned in the past quarters, our VPP deferred revenue amortization is included in oil and gas revenue but without any corresponding production volumes. So at the top of the oil and gas bars, we've highlighted that portion of our price realizations that are attributable to our VPP deferred revenue.

Looking specifically at oil prices and excluding deferred revenue, our oil price realizations for the third quarter were up slightly from the second quarter as the company benefited from trading month sales as oil prices declined during the latter part of the quarter. Looking at NGO prices, they were up 8% compared to the second quarter, and this is primarily due to increased demand for ethane causing ethane prices to be a little bit higher. Looking at realized gas prices for the quarter they were up 2% primarily due to lower third quarter basis differentials that the index points at which the Company sells it's gas.

Turning to slide 19 for review of production costs. Production costs for the third quarter were $11.36 per BOE down 1% from the second quarter. This decrease is primarily due to a 4% reduction in our base LOE offset by increased workover activity in Canada. Base LOE for the quarter was down mainly due to lower billings in our South African operations as well as increased production in our Raton field which caused our per BOE costs to decline plus as our ongoing -- as Tim mentioned, our ongoing cost control initiatives throughout the Company.

Looking at all the columns and all the periods presented, they all include VPPs. At the bottom of this slide we have adjusted base LOE and total production costs include the delivered VPP volumes, thus reflecting what our true per BOE costs are doing. You can see the base LOE costs have been relatively flat over the year while total production costs have increased slightly mainly due to increased production taxes which are correlated to the rising commodity prices.

Turning to slide 20 that shows our current hedge position, I'm not going to go over this in detail. But as Scott mentioned, I did want to point out that we have highlighted the new swaps that we have put on in the last 60 days. You can see that we've added 85 million cubic feet a day of gas swaps at $9.06 on a non-mix equivalent basis and also just over six million cubic feet a day -- of collars with the floor price of $10. Those are both for 2007. In 2008 we also added 15 million cubic feet a day at $9.10, NYMEX equivalent.

On the crude side you'll notice that in the -- for 2007 and 2008 we've unwound 4,000-barrels of day of oil production in 2007 and 3,500 barrels a day for 2008. We did that when prices dropped to the mid $60s. Those locked in losses will be reflected as a reduction in oil revenue over the original maturity schedule those swamps and so we've added in the appendix slide a schedule that shows the amortization of those that impact oil and gas revenue or oil revenue in 2007 and 2008.

Turning to slide 21 for fourth quarter guidance, as Tim mentioned, production guidance for the fourth quarter is 98,000 to 103,000 BOEs per day with the lower end of the range reflecting the timing of oil shipment in Tunisia and South Africa. Production costs for the fourth quarter are expected to average between $11 and $12 per BOE consistent with the first three quarters of 2006. Exploration and abandonment costs for the fourth quarter Are expected to range between to range between $45 million and $110 million with $15 to $75 million being drilling-related and $30 to $35 million being seismic related.

As Scott mentioned in our drilling area, the Flying Cloud well was unsuccessful AND SO that's the $15 million highlighted on the high impact at the low end of the range. As Scott also mentioned we are -- have ongoing drilling activity at our Norphlet acreage in Mississippi. That reflects the other piece of the high impact range. Looking at the majority of the remaining costs for the fourth quarter particularly in the drilling and seismic it's mainly related to our resource plays particularly in the Edwards trend that Tim's discussed, and the Uinta, Piceance and Tunisia areas. Looking at fourth quarter guidance for DD&A though the effective tax rate at the bottom of the slide, these ranges are similar to the third quarter guidance as well as our third quarter actual results and really represent business as usual type activity levels there.

I'd like to also point out as we have typically done in the past we've added a number of supplemental slides in the back that are new in addition to the ones that we've used on a recurring basis. I would encourage everybody to take a look them. I think you'll find them useful for not only for your modeling but your analysis of the Company as well. So with that, I think we'd like to go ahead and open up the call for questions.

Thank you. [OPERATOR INSTRUCTIONS]

Our first question comes from the location of Brian Singer with Goldman Sachs.

Thank you very much, good afternoon. I think you highlighted at the beginning 10% per share production growth target for '07 and the notion that CapEx will be a little more in line with what you are expecting cash flow. Could you delve that into a little more in terms of, are you looking to just spend next year what your ultimate cash flow will be or do you expect just the buffer to be a little bit less than that this year?

Yes, obviously it depends on the strip environment has varied significantly over the last 60 days. So it's more of a generalized statement that we are going to be more closely aligned. It may be equal to, it may be 10, 15% more. But I think areas of reductions will primarily be areas where such as the deep water areas where we spent capital in the early part of the year, such as Gulf of Mexico, West African, Argentine.

Obviously depending on the winter month, this winter will determine whether or not we see $5 gas or $10 gas depending on how cold or warm it is. That will have a great affect on it. But right now, I think the comment is that we'll be spending close -- more closely aligned with our cash flow. We're confident we're going to get a 10% production growth on a per share base.

Great. Could you provide any more color on your Cotton Valley position and what your expectations are for the wells drilled over the next six months?

Yes, they're -- they're not in our development wedge, but it's an additional opportunity we picked up over a year ago. We are drilling on the first well. We have several development wells to drill. So until we start getting production, we'll probably comment on it but that production growth depending on success is not in our numbers for 2007. So obviously if we're successful there, continue to drill, it will increase our numbers.

Great. Switching to the Rockies in the U.S. could you just give us an update on some of the exploration there? And then in Canada what are your thoughts on spending? You already see some other producers making with the decreased activity, is that something you've considered and any update on the Mannville?

Yes, well probably early indications will be cutting back on the Horseshoe Canyon especially being in a say $7-$7.50 gas volume or less. If you look on that return slide it is our lowest return slide as gas prices drop. And the primary reason is we shipped gas on alliance. And so Alliance has a fixed charge. And so that's obviously one area. Piceance, Uinta, is another potential area, depending on how successful our Entrada Dakota wells are.

Another area that we'll be looking at cutting back. Other exploration activity is really going to be centered on the next six months really focused on we're drilling five key wells on Tunisia. The next six months we have the Norphlet play, and then we'll probably drill another three or four Edwards prospects over the next six months. And then we have the two Alaska wells with Conoco-Phillips, huge potential. Obviously they'll be spudded sometime in January both on NPRA east and NPRA west.

And Brian, just to answer your question on Mannville. We have drilled the pilots and they're dewatering. I think our activity there will be mostly focussed on watching the data in terms of the water production levels and gas production levels and gas production levels over the next few months.

Thank you.

Next we'll go to Robert Morris with Bank of America.

Good afternoon.

How you doing?

Good, thanks. On the Edwards Trend, you said the last quarter, there were three prospects you'd be drilling in the quarter. But I noted today you said there was one new discovery. The two prospects that you were going to drill before, were those pushed back or were those not successful or what's the result of those other two?

I think the answer is -- two of those are still under testing right now. So we haven't really come out with the results on those two, Bob.

Okay so the other two that you're testing. So you still think that gross resource potential is one to three TCF, nothing's occurred here to change your view on that?

No. What you've seen in the presentation today was reflecting results from current drilling. We tried to be conservative as well.

And then just one additional question. Is it still about $1 billion that you need to spend to hit about 10% production growth next year? Is that the mark?

I think we actually have a slide in our investor relations packets. It's about $900 million per year. That's compounded over 2006 through 2010 time period. So it takes about $900 million a year. So the first couple years, we're spending about $500 million on Alaska and South Africa gas that's contributing either zero or little production growth. So the actual number to actually get 10% production growth is probably less than that. It's just that we are spending $500 million of capital on two projects that contributed nothing in 2006 and just a little in 2007.

Okay.

But on average, it's a good number to use, roughly about $900 million a year over a year over a five-year period.

Okay, thanks.

Next we'll take a question from the location of Sven Del Pozzo with John S. Harold.

Good afternoon. Regarding the Wolfcamp formation, you had indicated in the past that about half your wells might be targeting that zone. Is that still the case or more or less?

Yes. in the Spraberry trend area we are taking about half our wells to the Wolfcamp.

Okay and could you help me understand, I think you said this in the past, but if you'd be kind enough to remind me what the incremental costs of targeting that formation is and drilling and completion as well as incremental reserves per well.

We're getting -- we're about -- oh let's see about 20% increase in our well costs, we getting about a 20 to 30% bump in our reserves. So it's basically about $200,000 getting another 20,000 barrels plus -- 20 to 30,000 barrels.

Of those five wells in Tunisia over the next six months, will there be any spuds in a BEK block?.

Yes, Tim mentioned one well.

One well.

One well there. It will be pretty close to the OMB wells we talked about. We had two discoveries offsetting our BEK block that were made by an Austrian company recently which obviously has given credence to the fact that we think the whole block is productive now.

Yes. Okay and lastly, how -- what are your reserves on the Gulf of Mexico shelf and as possible production as well currently proven reserves?

Yes, I don't know the proven reserves. Our production next year is about 15 to 1700 barrels a day next year.

Okay. Thanks a lot.

Next we'll go to Robert Lind with Simmons & Company.

Good afternoon. Nice to see the continued positive results in the Edwards trend. But question for Tim. What is the capacity of a temporary H2S scrubbing unit? I'm trying to get an idea of how many wells can -- can actually be tied into one.

Yes, Individual units, it depends. There's three or four different sizes that can go anywhere from about 5 million a day in terms of gross production, they can handle up to ten roughly. And there's possibilities to increase, but that's going to be your range, five to ten million a day.

As you remember, the wells typically will I.P. at 3.5 million a day, 3 to 4 million a day and decline through times so you have more capacity through time as the first wells fall off.

So are you tying a well in and then just waiting until you get a line built to the Pawnee plan before you take it off?

No we -- our options are in various areas that outlying significantly, Pawnee -- remember this is a 250 mile trend. We have wells that are a long way away from Pawnee. In those areas we pretty much had no choice but to go ahead and establish independent amine treating units in and around those wells. However in the areas closer to Pawnee we're looking at tying in some small pipeline expansion to tie in gas to the existing Pawnee field. Those are some things we'll be heavily looking at in '07.

Thank you. Are these leased or owned?

Combination thereof. We lease and own them.

And are they included in the $3.5 million well cost?

Yes.

Okay.

That's a -- that's a drilled and completed cost. Completed and put on production. In the case they're leased, of course, the cost related to lease it goes through LOE.

Got you, that's all I had gentlemen, thanks..

Next we'll take a question from John Wolff at Credit Suisse

Hey guys. Good job on the [FX restrain] and the hedges. I was wondering if you can give a little more detail on what some of the more obvious chunks are from going from 1,4 billion down to 1.1 billion? I know you kind of give a little color. Is there sort of big chunks we could think about?

Yes. There's about $150 million chunk of all our deep water activity in west Africa and the Gulf of Mexico. There's probably a good $100 million in Canada and Piceance, Uinta -- call it gas plays that are more sensitive to probably more toward your price deck, John.

So in terms of Canada and Piceance is that sort of a wait and see issue on gas or will you set a budget lower?

Yes, it's something that's held by production. Like I mentioned earlier, this winter will determine whether or not we'll see $5 gas for a few months or 9, $10 gas. We could reduce our budget further if we see the $5, $6 gas scenario or we could increase it. So more to flexibility. But the areas that we control, we don't have long term rig contracts in those areas. And they're still good returns but we can just -- we can deliver on it later on.

The other thing to point out there, John, is that in Uinta Piceance we're spending a lot of money this year on getting our three CBM pilots projects up to speed. Those being Castlegate, Columbine Springs and Lay Creek of course in the Sand Wash basin. And having done that this year, next year has more to do with watching how the wells perform. There's a heck of a lot less capital next year than this year. That also adds into the reduction.

Right Okay. And with Canada do you have to make some decisions fairly -- fairly soon in terms of winter drilling programs?

Not in the Horseshoe Canyon, Horseshoe Canyon we can make it late because we can drill all year long in the Horseshoe Canyon. It's got more flexibility.

It's the case that if we were to have high gas Horseshoe Canyon needs a place to turn on the switch too and get rigs out there.

That makes sense. And given the positive performance at the Hugoton field, is there any chance that certain kind income interest or MLP structure?

If you recall, Hugoton's tied up until 2010 by our volumetric production payment.

That's right.

It all comes back to us in -at the end of 2009, 2010. Obviously there's -- we're continuing to observe the market. There's little liquidity in the market. There's probably going to be seven or eight MLPs trading, potentially one royalty trust trading so obviously we'll just continue to watch those.

Got it.

And see how they trade. Makes sense.

Next we'll take a question from Dan Morrison with Aperion Group.

Most of my questions have been covered. But I wondered if you could elaborate a little bit on -- your use of Chinese tubulars and kind of more interestingly pumping units. Are you all having to do a lot of work on the ground yourself to establish quality or how hard is it to QC the equipment you're getting?

I think, Dan, the answer is we've had -- we've used sparingly the Chinese pipe and pumping units this year 2006 and we've found really, really good results from it. Essentially zero issues from the standpoint of quality. That makes us real comfortable looking ahead, in terms of higher utilization rates in 2007 . It's imperial evidence.

Could you ballpark your, you know, kind of average cost savings there?

I would characterize it as 10 to 20% roughly.

10 to 20% cheaper?

Yes.

Okay, thanks.

Next we'll go to Rehan Rashid with Friedman, Billings, Ramsey

On the slide number 12, the 150 to 325 BCF P90 to mean, what would drive the higher end of the range? What else do we need to see?

Yes, Rehan, the key would be 3-D seismic as Tim mentioned. And then, if you recall we showed in March our Pawnee it took about six or seven years to take it from about 90 BCF to 300 BCF. That was a combination of horizontal drilling, extension drilling and 3-D seismic. So that'll be the key to drive it to the mean and even to potential the P10 number which is even higher than the number that Tim mentioned. So it will be the 3-D seismic and appraisal drilling.

Remember, Rehan, the particular numbers I'm throwing out there are related to drilling that's already been done, but it's only in those wells in those areas. We'll also be doing substantial exploratory drilling along trend as the next few years progress as well. Those will add production and reserves we hope as well.

You did say 50% production above the current rate which is around 138mmpd?

That's correct. By the end of next year.

Fair enough. On South Africa, what's your net again, please?

It's 45%.

45%.

The project will work up to about 45 to 50 million a day would be our net. We won't hit it immediately, but it will work up sometime in 2008 up to that number.

Maybe Alaska is remind me what's the ramp looking like that comes on line early mid '08 and starts, ramps up to by when?

We'll be drilling development oils out there, Rehan through 2010. So actually it's out in that time period when it's hitting production with all wells on-line.

Yes but probably four to five -- 4,000 barrels net. Or actually have a gross standpoint will be about six to 7,000 climbing on up to about 15 to 20,000 by 2010 on a gross basis.

Okay and on the CapEx front, once again $900 million and change for a 10% growth the next few years?

That's our slide that shows that's what it takes to grow 10% per year.

Perfect and -- go ahead.

Our CapEx will obviously vary depending on commodity prices and risk success if we have success in several key areas like we are Edwards, Tunisia, other areas and obviously CapEx may change. Like the growth rates would change significantly too.

Sure, in terms of F and D, the number for this year is 15 to 20 and next year does it -- do I remember correctly it drops down to 10 to 15?

Exactly. 10 to 15 '07 to '010 and 15 to 20 this year.

For this year, any particular progression that will help you get comfortable with lower end or upper end of the range or just again, wait and see?

No, we still expect they will be within guidance.

Our next question comes from Gill Young with Citigroup.

Hi. With Piceance Uinta -- well Piceance certainly the CapEx reduction, Tim, as you were saying is in part because you not [inaudible] -- watching them. But in Horseshoe Canyon, how much production would you lose by that drop in CapEx?

Well, the wells, of course, out there make 85 MCF a day on average. Okay, so pretty much can do the multiplication. Our net share of those wells typically is about 70% net, so each wells is 50 MCF per day. Horseshoe Canyon accordingly is a manufacturing process. Laying down a rig for a while really doesn't have any real substantial impact on current production.

What's the cost per well?

Typically about $400,000 to $425,000 Canadian dollars.

On a 100% basis?

That's correct that's eight eights.

In Edwards, is the limiting -- is the limiting thing that limits your activity there the waiting for the 3-D seismic to get done or is there something else?

That's probably the number one driver is 3-D seismic, making sure were we put I'm going to say 75 to 85% of your development wells will be horizontal. We have to make sure which direction to go through the reefs on.

So once you get that 850 square mile shoot done how much can you accelerate the program there, do you think?

Go back to our March slides. We show a big ramp-up in production in '08, '09.

We still feel that is -- we're confident in those numbers.

But is that -- you know how -- can you talk about how many wells you'll be drilling to get there?

It's about 55 to 60 per year for the next several years. That's with about six rigs. It takes ten wells can drill -- a rig can drill about 10 wells per year. But right now we have six rigs scheduled for next year. And unless we get more rigs and depending on the 3-D seismic, obviously we can increase that with time.

Another thing is, Gill, as I mentioned in the call, this is a relatively limited infrastructure area. We have to lay pipe to some of these areas. We also need to get amine treatment out in some of these areas, notwithstanding configuring this in the cases we can get gas down to Pawnee. We have a bunch of infrastructure work to do too. And that's clearly today a limiting factor but the longer you go it's not.

Right, right. Okay, thanks.

And we'll take a follow-up question from Rehan Rashid.

In Spraberry the Wolfcamp success have you seen enough to have some view on the outside that you discussed? I think it was 100 million-barrels and change. And also with Raton production better than expected, again what implications on the two P and three P reserves that you have?

Yes. We will update our resource potential on Spraberry but I think the Wolfcamp obviously is going to increase the number by year-end 2006, early '07, so the 100 million-barrels obviously will be increased depending on how much of that we book this year. We still see a lot of opportunities in the Spraberry and adding the Wolfcamp is very positive.

The Raton will continue to -- as we continue to drill extension wells, successful extension wells and with the production ramp-up doing much better, obviously we're more and more confident in that play. And so we're obviously very pleased with those results this year.

So, once again, the success so far this year in the Wolfcamp gives you comfort with continuing to raise the two P, three P number there?

Exactly.

Okay, okay. That's it, thanks.

And gentlemen, at this time there are no further questions in the queue. Mr. Sheffield I'd like to turn it back to you for any additional or closing remarks you may have.

Okay again, I'm sorry about -- as Frank said, we're sorry about change, late change due to conflicts. And obviously we're pleased with the quarter. We feel like that we had a strong quarter. Looking forward to reporting year-end results sometime in late January, early February. We'll be seeing you all on the road over the next several weeks. Thanks.

This does conclude today's Pioneer conference. We thank you all for your participation. You may now disconnect your lines.