先鋒自然資源 (PXD) 2007 Q3 法說會逐字稿

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.PXD.com. Again, the Internet site to access the slides related to today's call is www.PXD.com. At the website, select Investor, then select Investor Presentation.

The company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in the last paragraph of Pioneer's news release on page 2 of the slide presentation and 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, Mr. Frank Hopkins. Please go ahead, sir.

Good day everyone, and thank you again for joining us this quarter. Let me briefly review the agenda for today's call. Scott Sheffield will be our first speaker. He's going to discuss the third quarter highlights, our reduced capital spending plans for 2008 and the good progress we're making towards achieving our production growth and F&D goals. After Scott concludes this, Tim Dove is going to provide an update on what's going on with our operations. 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 up the call for your questions.

Before turning the call over to Scott, please let me remind you that on July 26, we announced that a registration statement was filed with the Securities and Exchange Commission for Pioneer Southwest Energy Partners LP, the master limited partnership that we are forming for the purposes of owning and acquiring interest in oil and gas assets in the Spraberry field. A copy of the prospectus for this offering when available can be obtained by contacting one of the three underwriters listed on slide 44 of today's presentation. The rules of the Securities and Exchange Commission limit the nature of the information that we can provide you about the MLP and any other MLP plans at this time. As a result, we do not plan to take any questions related specifically to the MLPs in this call or in follow-up meetings. We refer to you the press release and registration statement for further information. With that, I'll turn the call over to Scott.

Thanks, Frank. Good morning. Starting out on highlights on slide number 3. We had obviously a great quarter. We reported third quarter net income of $102 million, or $0.84 per diluted share. We were at the high end of our production gain for third quarter, about 109,000 barrels of oil equivalent; excluding Canada, 101,000. When you look at it versus 12 months ago, third quarter '06, we were up 11% when you include Canada. Excluding Canada pro forma we were up 12% over the last 12 months. What's more important is our four core on-shore assets: Spraberry, Raton, the Edwards play in south Texas and onshore Tunisia. We were up 21% versus 12 months ago, third quarter of 2006. We're delivering on our South [Coast] gas project, coming on on schedule in late third quarter '07. The Oooguruk project up in the North Slope is still on schedule. Tim will talk more about that.

We have already announced the fact that we had another three discoveries in Tunisia and two more in our successful South Texas Edwards trend, continue to significantly grow both of those projects. In addition, we announced this morning two attractive bolt-on acquisitions. In the Spraberry Trend area, for $90 million, we acquired 38 million barrels of oil equivalent of resource potential. In the Barnett Shale where we made our first acquisition the first part of this year, another important acquisition for us, $150 million for 400 Bcf equivalent in the resource potential. Tim will talk more about the details of both of those transactions.

As we have in the past, we continue to reduce our share count as we see opportunity to buy shares at low prices. We did buy back 3.7 million shares in the third quarter at an average of a little over $43 per share. Also important, we announced the agreement to sell Canada, Canadian assets for $540 million, which we expect to close during the fourth quarter. Then our MLP Frank mentioned it is on schedule to get this project done sometime during the fourth quarter of this year. The proceeds from both the MLP, IPO and the Canadian divestiture are all allocated to share repurchases, bolt-on acquisitions as I mentioned, and also debt reduction. Due to the fact that we're getting close to the end of the year and also with three acquisitions, the two that we announced, plus the Petrogulf deal, we are comfortable in announcing the fact that we all-in finding cost of $14 to $17 per BOE and reserve placement greater than 300%, pretty much hitting at the higher end of our targets. Midpoint range of the finding costs, the high end of reserve placement. We'll talk a little bit more about that as we move forward.

Slide number 4, delivering consistent production growth, establishes what we've been doing quarterly, emphasizes that we're on track to deliver 12% production per share growth in 2007. And you can see on the bottom what's happened to our outstanding shares -- continue to come down, 2006 from almost 128 million, averaging the first nine months, 121.8 million shares, we're now down to 119.7 million shares which we'll report something close to that the year end, 2000 and this year. Slide number 5, our 2008 capital is something we stated in early 2006, with this refocused strategy onshore, primarily. Our 2008 capital is in line with our cash flow. We're reducing our CapEx from $1.45 billion, in 2007, to about $1 billion in 2008 as we have announced previously. The major reductions are in our two big projects, both in Alaska and South Africa, also the elimination of high impact expiration and the divestiture of Canada. Most of the capital would be focused on Spraberry, Raton, Edwards, and Tunisia and some [Madurai] drilling which Tim will talk about starting up that rig toward the end of the fourth quarter of this year. So you can see pretty much where the capital is focused. The moving into -- right now with strip prices, we are in excess cash flow position for 2008, with significant excess cash flow in 2009, '10 and '11 moving forward in our plan.

Slide number 6, little more background on 2007 F&D estimate. Obviously our reserve adds have been from our successful drilling and core onshore areas, primarily the Spraberry Trend area, the Raton, Edwards, and onshore Tunisia, followed up by the recent acquisitions in Raton, Spraberry and the Barnett Shale. As I mentioned already, all-in finding cost $14 to $17 per BOE. Organic F&D, expected to range between $17 and $20 per BOE. Excluding Spraberry and Raton PUD drilling, the organic number would have been somewhere between $11 and $15. Again, I mentioned reserve replacement should be over 300%.

Slide number 7, again, just showing the fact that it's important to reduce shares which is our commitment over time. We have bought back about 24% over the last three years of our outstanding shares. Average price, little bit over $43, coupled with the fact that we bought 3.7 million shares during the third quarter of 2007, a little over $43 also. We've utilized a little over $200 million this year so far of our $750 million program. Slide number 8, just emphasizing the fact in today's weighted price toward oil and crude related products, including NGOs, most of our growth in revenue is going to be more primarily focused on oil related projects -- Spraberry Trend area in west Texas, Oooguruk in Alaska, Tunisia onshore, and then South Coast Gas as we have mentioned before is tied to Brent pricing. The gas is coming from Raton, Edwards and Barnett Shale. So again, 65% of our incremental revenue growth coming from oil related projects.

Slide number 9, again, just emphasizing the fact that our commitment of growing production per share is happening, delivered on 18%. Our first year, 2005, 2006, wound up being around 12% from '06 to '07. Obviously with a lot of projects coming on we expect to deliver something north of 12% plus per share for -- 2008 to 7 going forward. Slide number 10, cash flow and return on capital employed increasing significantly. As I mentioned already, we expect to be free cash flow neutral or positive in 2008. In addition, return on capital employed expected to improve from 6 to 7% in 2007, or really double over the next three years to 12 to 14% in 2010 primarily driven by production growth, legacy hedge expirations, reduced VPP obligations and improving commodity prices. But taking the company from about an $800 million to $900 million cash flow in '07, we'll be doubling it by 2010. Let me now turn it over to Tim Dove, talk more detail on our assets.

Thanks, Scott. As Scott has already alluded to, our third quarter results are really further evidence of the ability of Pioneer to show consistent growth in our assets, specifically from our core areas, and to deliver on our growth initiatives, starting off here in 2007. We think we have a great deal of confidence we can continue these type of growth through 2010. That starts with one of our cornerstone assets, of course being the Spraberry Trend area, where about 50% of the company's pre-reserves reside. We've been able to show double-digit growth in Spraberry for some time. In fact, if you look at the third quarter results, increased production by about 14% compared to a year ago and 12% compared to the nine month periods. We do expect the continuation of that level of growth. In fact, we're calling for 10 to 15% growth in 2008. That's after the effect of subtracting production that will be attributable to the public following the IPO of PSE.

We have been very successful over the years in acquisitions and we're continuing that trend. I'll mention on the next slide a little more detail regarding the Spraberry acquisition we just made, but we'll continue to focus on bolt-on transactions in this key asset. We are in the middle of a substantial drilling program. We have 16 rigs running and have drilled about 300 wells out of a 350 well program for this year and essentially are on schedule to complete that by year-end. And the majority of those wells are still being drilled to the deeper Wolfcamp where we're co-mingling what Wolfcamp and Spraberry production and adding incremental reserves and production in the neighborhood of 20%, which is incrementally adding a lot to the economics of these wells.

Turning to page 12, a little bit more detail on our fourth quarter Spraberry acquisition. We do have a substantial track record of success in adding bolt-on transactions in this field. Since 2000, we have acquired $430 million worth of properties, equating to 190 million barrels proved. So the economics of acquisitions in Spraberry has been excellent as well. On the current transaction -- it's a $90 million purchase price, which is acquiring today's production anyway of 700 barrels of oil equivalent per day, but more important importantly, it adds over 600 undeveloped locations into the drilling inventory at a very high working interest. And accordingly, along the lines of the economics I mentioned in prior transaction, this one also is very attractive when it comes to the acquisition F&D and the ultimate F&D in the project as we're prognosing about 38 million BOE of net resource potential through the life of the project. And in that drilling will also be Wolfcamp potential as I mentioned in our normal drilling campaign. We believe the economics is going to be very attractive of the drilling of the assets acquired in this transaction as we're looking forward. Most of the gas will be processed through our existing [Midkip Venetton] plants. Of course these are the plants where Pioneer has the option to increase our working interest over the next couple years up to 49%. And these are the typical Spraberry long life assets, slow declining with stable cash flow. So they fit very well with the Pioneer model.

On slide 13, I think can you see from the graphs down below to the right what's happened with production. We're obviously extremely pleased with the results from our Edwards expansion and we're starting to see the substantial effects of our recent drilling on production. In fact, production was up about 63% this quarter versus the same quarter last year. And we do anticipate production growth to continue in the neighborhood of 25% into 2008. And that is as we bring on some of the new fields that have been discovered in the past and continue our aggressive development drilling campaign. In late October we announced that we had made two new field discoveries, which now means we've added a total of eight new fields to the trend. We are in the process now of completing a 35 well campaign this year. Most of that is development drilling. As we said, we're holding off on some new exploratory drilling until we have the seismic programs complete. We've had a substantial amount of success both with regard to new wells and existing wells in the Pawnee Field of using new multiple isolation frac technology to increase EURs per well, particularly by 1 and 1.5 Bcf at a cost of only about $1 million per well. These have substantially added to the economics of drilling the Pawnee and Edwards extension wells. We're about 45% complete on our 900 square mile 3D seismic surveys in the area, up and down the trend, and we are making substantial headway in terms of completing our treating and pipeline facilities that can allow us to increase production even further. I did want to mention even though it's not on the slide -- we do have two wells on production on our Mississippi field area that continue to produce about 7 million to 8 million cubic feet a day combined. We're going to be shooting a 120 square mile seismic survey in that area to define the next drilling campaign locations.

Slide 14 is on Raton. Raton has really had a great comeback year. You may recall it was slowed considerably by bad weather in the first quarter. It's now increased its run rate above 10%. In fact, production in the third quarter was about 11% over the same quarter last year. We still believe that we're on a track for about a 10% growth rate this year, even though we suffered that horrendously bad weather in the first quarter. And we're also looking for about a 10% growth rate in 2008. Importantly, Raton continues to benefit from getting or receiving mid-continent pricing. In fact, you look at today's data, mid-continent differentials, basis differentials are about $0.75. Where, and you went to Piceance areas west of Raton, differentials are in the neighborhood of $2.50 to $3. We clearly are the beneficiary of being able to move this gas into mid-continent markets. We're in the midst of a substantial drilling campaign that we're going to complete on schedule here at the end of 2007. About 300 wells will have been put on line during the year. We're doing a good job in Raton of controlling costs. That's where we have our integrated well services model that continues to give us benefits or cost control when we're pretty much providing about 65% of our own services. And we are operating two Pioneer owned rigs so that drilling costs are essentially being held constant even though we've been in this escalating cost environment for a couple years. One important aspect of Raton that we continue to be focused on is improvement of and optimization of both wellhead and field compression as that's a very key component to growth and increased production in a coal bed methane field. Incidentally, we did shut in some -- you went to Piceance gas in mid-September, about [6 million] a day. It was receiving less than $0.10 per Mcf. That gas is now back on line as of November 1st as we've been able to secure higher prices for that gas.

Turning to slide 15, Scott alluded to some more detail I would provide on the Barnett Shale acquisition. This is an important transaction as we continue to take steps to build our Barnett Shale interest into a core area. This acquisition is an important contributor to that. $150 million acquisition, it adds 37,000 gross acres, predominantly in Parker County and a similar amount more in the expansion areas. But it also importantly will add over 300 drilling locations. We have existing 3D over most of those and about 480 Bcf of resource potential with today only 80 Bcf we consider to be approved. Current production about 15 million cubic feet a day. This will be one of the areas we begin to target for a ramped-up drilling campaign in 2008. We do add that to a small existing acreage we have, about 13,000 acres that has an existing 150 drilling locations and principally that's in Wise County where we're drilling wells on a 50% basis with Devon and having very good results. We're also going to be shooting seismic up in Wise County to further delineate drilling opportunities there.

On slide 16, Scott has also mentioned our success in Tunisia which has really been phenomenal. We continue to have a great deal of success there from the drill bit. Production in the third quarter essentially doubled versus that in the same quarter last year and we anticipate production will essentially double or be up approximately 90% in 2008. And that's really coming from a combination of existing discoveries we've made, specifically in Jenein Nord, adding those into production and drilling more wells in Jenein Nord where Pioneer today has a 100% working interest. We believe that will go to 50% upon the completion of the development planning as ETAP backs in for their share of the development. However, at 50% it can have a significant impact on Pioneer. We mentioned in mid-October in a press release we had made two discoveries that tested approximately 5,000 barrels a day. We're pleased to announce a third well that actually itself tested over 5,600 barrels a day, so that now we can say over the last three discoveries they've averaged a testing at a combined rate of over 10,000 barrels a day. Again, very significant volume and relatively quick tie-in. The production facilities that are being put in place should be in place to begin at least production of wells probably mid-November or latter part of November. In the early stages, we'll be producing some volumes of oil but most likely won't have any total sales volume, in other words, cargo size availability of oil until the early part of 2008. We're going to have capacity of 10,000 barrels a day. Currently, in other words, here at the end of November, increasing to about 20,000 by the time we get to the second half of 2008.

And in a couple areas I'll show on the next slide, we have substantial 3D shoots underway, that will be the linchpin for future drilling. Adam which is the block operated by ENI, we had a discovery there called Nadir, 4,000-barrel a day well. And that's quick to get on production because of the existence of facilities on that block. And finally, [Anagi], where we've taken over operatorship, is the site of a 3D program as well in 2008. Drilling still continues. We have our own H&P rig, drilling wells in Tunisia. We have two wells planned in Jenein Nord. One is drilling as we speak. Another well planned in Adam to complete this year's campaign and today's view is we would have 15 to 19 wells to drill next year, again adding to the productive capacity of these three blocks. We are working hard on the possibilities of a longer term gas sales program. What's needed is a new expanded pipeline from the southern gas areas into northern markets. And so we're working with a conglomeration of several operators in the area to decide whether or not we can provide enough gas reserves and a project to move gas to northern markets. That's a project that will probably not have much impact though until the early part of next decade.

On 17, again, just more of a cartoon map regarding prospectivity. Clearly, the map shows -- number one, we've had a great deal of recent activity. But it has substantial up side and running room in this country. Specifically you can see on slide 17 the black triangles -- those are 10 recent discoveries in 2007, seven of which are in our operated 50% after back end block Jenein Nord, two in Adam and one in BEK. You'll also see that the three wells to be drilled are shown in yellow for the remaining part of 2007. And importantly, the red blobs here really show prospectivity, prospects, and leads for future drilling. I mentioned substantial seismic shoots going on. Can you see in the Southwest part of Jenein Nord in the orange we have an existing 3D shoot going on, in addition to which we have the same in the northern block called [Anagi] and we hope to be able to reap the benefits of those 3D seismic shoots and begin further drilling as we get into the latter part of 2008. So Tunisia is really doing some good things for us and is going to be a major contributor to --- number one, F&D cost improvements, but also production growth and has our strongest economics in the company.

Slide 18, South Coast Gas, we announced at the end of the third quarter that we've commenced production from this project from four wells. There is one additional well that we are anticipating coming on here probably near the end of the year. There was a problem with the subsea control panel on this well and that is in the process of being replaced. And so we anticipate that well can be turned on by the end of the year. We'll increment production by doing so. Our 45% of the production during in the fourth quarter from these wells is expected to be about 15 million to 20 million cubic feet equivalent per day given the fact that we have pretty substantial condensate production from this field as well. Of course, peak production from this project won't come until the latter part of '08 or end of '09. That's because one of the major wells for contributing to the project is a gas injection well in the Sable oil field. And the Sable oil field of course has been extended in terms of its life due to the high oil prices that are in the market today, as well as excellent performance of the wells. And so it's the case that these initial five wells will really be on production until the decision is made to shut the Sable oil field in and begin to produce what's now reinjected gas. We are separately evaluating whether it might make sense at some point to simply produce Sable oil and gas simultaneously. That would need some work to be done at the gas to liquids plant on shore in order to be able to handle the incremental liquids. But it may be a lower cost alternative as oil production declines looking ahead. Finally, the gas prices here, as Scott already mentioned, are tied to Brent so we're getting strong gas prices for realizations.

Slide 19, Oooguruk, of course we've been very busy putting this project up to schedule. It's doing well. We now have the rig installed and we expect to start drilling in December, recognizing the first wells will be disposal wells and injection wells, typically. That means we really won't be drilling, producing wells until the first half of 2008 and we anticipate that we won't really see sales of oil until about mid-year. That's as expected. The reason being of course we have to fill the pipeline on the one hand and in addition to which, in the cold temperatures there, we have to be very sure of our flow assurance. And so that's kind of the timeframe that we've been thinking that we'll see first sales of oil out of Oooguruk, probably mid-2008. Peak production of course as we continue drilling won't come until 2010 at about 15,000 to 20,000 barrels a day on a gross basis. It is a substantial resource. We'll just start booking some of the reserves at the end of the year but there is substantial potential as we see 70 million to 90 million barrels of gross potential from the existing field. And there are expansion opportunities. There are contiguous reserves we think that can be reached from this island and in particular, one area of proved reserves that we know can be reached with extended reach drilling from the island that could have a substantial impact. But that's down the road for us.

On slide 20, Cosmopolitan -- this, of course, is an appraisal well, offshore of the Cook Inlet. We're drilling an extended undulating horizontal well from the shore to a resource about two miles off-shore. It's really proved to be about 30 million to 50 million BOE on a gross basis. Pioneer now owns 100% of this resource. The well has been very successful to date in that we essentially reached TD. We have drilled about 5,800 feet of lateral section and we're in the process of working towards completing this well and putting it on what will be several weeks of testing. The next time you hear from us on this will probably be the next quarter when we can report about results from the drilling of this well. With that, I'll pass it over to Rich for discussion of the financials for the quarter.

Great. Thanks, Tim, and good morning. As you heard from Scott and Tim, the operations are going very well. Production is continuing to grow out of our core areas. As a result, our financial results are continuing to improve. For the third quarter, we did report $102 million of net income or $0.84 per diluted share. This is our highest quarterly net income that we reported thus this year, so a good trend moving forward. Included in net income is discontinued operations which are associated with our Canadian results for the quarter. That was $9 million or $0.07 per share. On a continuing operations basis, we had net income or income of $93 million or $0.77 per share.

The quarter did include two items I think are worth noting. First, for the second quarter in a row, we were able to sell a portion of our Alaskan petroleum tax credits which resulted in an $18 million after tax benefit to the quarter or $0.15 per diluted share. The quarter was negatively impacted by higher DD&A rate in the Uinta/Piceance Basin area where we had an incremental charge of $11 million after tax or $0.09 per share. This is primarily related due to low quarter end Rockies prices where it was $0.60 per Mcf at spot prices into the quarter, which had the effect of reducing our proved reserves downward in the area and therefore increasing our depletion that we recognized for the quarter. As we look forward into the fourth quarter, gas prices in the Rockies have improved and have averaged about $4 per Mcf in October and so currently I don't anticipate seeing that type of DD&A charge in the fourth quarter and really expect those proved reserves to come back at a $4 gas price. We'll substantially get those reserves back into our reserve basis at year end for fourth quarter depletion purposes.

Turning to slide 22 and talking about prices, in the green bars there you can see oil prices are up 16% to $70.27 for the third quarter as compared to the second quarter. This is due to primarily the continued rise of oil prices over the quarter. NGL prices are similarly up 9% to $42.48 per barrel from $39.11 in the second quarter. Also the benefactor of higher oil prices, causing NGL prices overall to move up. Looking at the blue bars, we look at gas prices. Gas prices for the quarter were down 6% compared to the second quarter, to $7.11 per Mcf. As most of you are aware, we've had weaker gas prices given the high levels of storage we are experiencing today. That has put weakness on our gas price realizations. We have benefited from hedges as you see at the bottom there to the tune of $1.06 for the quarter related to hedges that we had in place with respect to gas.

Turning to slide 23, to look at production costs, if you look at the second quarter bars and the third quarter 2007 bars, you can see that they are fairly flat by category from period to period. We did see a slight increase in our base LOE. This is primarily related to our South African Sable oil project that has a large fixed cost component of LOE associated with it. And as that production declines, our per BOE basis continues to go up a little bit. Also impacting the quarter we had had a slight increase in labor costs in our field operations. And then also our salt water disposal costs have increased as we have drilled some wells further away from infrastructure. And so we've had higher transportation costs associated with that salt water disposal.

Turning to slide 24, we look at our hedge position as of November 2nd. You can see on this slide we've got lots of detail of what our hedge position is. This does include those hedges that we plan to assign to the Pioneer Southwest Energy Partners at the close of the IPO and those are reflected on slide 34. The important thing to note here is that we have added 80 million cubic feet a day of 2008 gas swaps, between $8.25 and $8.50 per Mcf, further protecting our capital budget and cash flow stream for 2008. In addition, we have added some first quarter 2009 gas hedges above $9.20 per Mcf. We did put on a couple of oil contracts for '08 and '09 at north of $70 per barrel.

Turning to slide 25, and changing focus to look at fourth quarter guidance, production for the fourth quarter excluding Canada is expected to be between 101,000 and 106,000 BOEs per day, reflecting continued growth in our Spraberry, Raton, and Edwards projects, as well as bringing on line this South Coast Gas project that Tim and Scott mentioned. Production costs for the quarter expected to be $11.75 to $12.75 per BOE. This is $0.25 per BOE higher than the last quarter guidance we provided and really with the increase in higher oil prices we do expect production taxes to go up since they're directly correlated. And that's causing the difference or the increase in net per BOE metric. Exploration and abandonment costs for the quarter are anticipated to be $40 million to $70 million, primarily driven by activity that Tim mentioned in Tunisia and our South Texas Edwards Trend play where we both have seismic and lower risk exploration and extension wells being drilled during the quarter. DD&A is expected to be between $10.50 and $11.50 per BOE for the quarter, assuming that commodity prices stay in the range they're running today. G&A is expected to be $30 million to $34 million for the quarter. Interest expense is expected to be $38 million to $42 million, increased from the second quarter primarily due to us no longer capitalizing interest associated with the South Coast gas project that we brought online, and given that we have a higher debt level at the end of the quarter until we close our Canadian sale and MLP IPO that we'll be allowed to reduce debt at that point. Cash taxes for the fourth quarter expected to be $5 million to $10 million, principally related to Tunisia, the only area that we're paying cash taxes today. And then our effective tax rate overall expected to be 40 to 45%, consistent with prior quarters.

If you look at slide 26, we do provide a number of slides in the back for your additional information relative to the third quarter as well as modeling questions, so I encourage you guys to look at those. And then at this point, that really concludes our prepared remarks, and we'll open up the call for questions.

Yes, sir, the question-and-answer session will be conducted electronically. (OPERATOR INSTRUCTIONS) We will pause for just a moment. We will take our first question from Ted Izatt with Bear Stearns.

Hi. Congratulations on your quarter.

Thanks, Ted.

You're welcome. On the -- very good results, yes. On the -- one of the issues Moody's had with their review is the organic F&D costs in North America. So you gave some guidance on your F&D costs and so forth. Where would you stand on that one issue?

Yes, I think it's on that slide I talked to, Ted. There were $17 to $20 organic. If you take out -- everybody knows we do a lot of PUD drilling in Spraberry. If you take out the PUD drilling in Spraberry Raton, it's $11 to $15. Most people calculate it in the $17 to $20 range. So it's down substantially from the last two years.

Okay. Thanks again.

We will take our next question from David Tameron with Wachovia.

Good morning.

Hey, David.

Question for you. Looking out to 2008 CapEx, I know it's a preliminary figure, but as you look out and go to the board meetings, how do you compare your outlook today versus six months ago -- meaning your CapEx is down from '07 levels and you're still targeting the same growth. How much of that is cost related? How much of that is getting over some of the platform installation type big projects you did this year? Can you talk a little bit more about CapEx?

In general, that slide pretty much outlined it. Oooguruk and South Africa were two big expenditures the last two years, high impact expiration the last two years was big. It's going to zero. Canada has been running $70 million to $80 million to $90 million per year. It's going to zero. So that's at most a reduction of about $400 million to $500 million. So we're pretty much keeping spending fairly close, maybe a tad less, but fairly close to what it is on the four core on-shore assets. Spraberry, Raton, Tunisia and Edwards and then followed up with Oooguruk drilling which Tim mentioned will start up here late fourth quarter. So with gas prices -- gas prices could easily swing between $7 and $9. That's what these recent uplift the last two weeks, it's been down the last two days, the reason we put on some more hedges. So I think we're about 35% hedged on natural gas for 2008. That helps protect the budget. We feel pretty confident that cash flow will be $1 billion or higher in this marketplace and that we can limit the CapEx to about $1 billion. The key swing factors to any increases will be continued success in Tunisia and also any Edward expiration wells.

And year-over-year, what's your general expectation on what you're building in on the cost side?

On the cost side, drilling costs are going to stay pretty much flat because we contracted almost all of our rigs from mid- to late 2006 through about mid- to late 2009. Steel costs, we've got all of our bids in already. It's flat. I know Tim and Danny, I don't know if you have any update on our pumping services bids. You all want to comment on those?

We are currently seeing, Scott, a reduction in the pumping services bids in the neighborhood of 10 to 15% compared to 2007.

Okay. So those three components probably make up 80 to 85% of the typical well in all of our four core on-shore areas. So it should be fairly flat to maybe down.

Okay. And one question, I'll let somebody else jump on. The Barnett transaction, can you talk a little bit more about the structure of the deal, who you bought the acreage from, what the royalty terms are, lease terms, can you give us anything that you care to share with us?

We didn't mention the seller's name because as an agreement between the two parties. We have been targeting -- we can't compete with the top three or four producers in the Barnett Shale, so we're targeting Tier 1 acreage, which is very good economics. As you can see, most of the acreage there we acquired early this year and also in this transaction, focused on Tier 1. A typical well will come in about 2 million to 2.5 million a day. So still very, very good economics and $8 price deck. What's interesting, I don't know if Tim mentioned this, was that a lot of this acreage is held by production. So we don't have to go out there and start ten rigs, 15 rigs. So one thing very, very positive. So it's a very good transaction for us. We're targeting transactions as I mentioned below the radar screen of the top four producers in the Barnett Shale so we can help build a core position.

Was it a public or private company you bought this from?

I cannot say.

All right. Thanks.

Our next question will come from Robert Christiansen with Buckingham Research.

Along the same lines -- good morning. Hi, Scott, and everyone. Your plans for the Barnett Shale in terms of well count, I mean, you've said you participated in five wells with Devon but with 150 locations in one area and 400 in another, what kind of well count can we expect to see, let's say, '08, '09, 2010, what sort of ramp is in your vision?

Yes, I think you're going to see a more ramp up. We are ramping up a lot more than the five to six wells we drilled this year. Due to the fact we are committed to spending $1 billion in cash flow, it's going to increase a lot next year. But we don't need -- you can look at our production growth. If our on-shore assets between our four key areas are up 21% over the last 12 months and we still haven't brought on our big gas well in South Africa, we haven't brought on Alaska and we haven't brought on Jenein Nord, we don't need to deliver a bunch of more production growth for 2008. Building up the Barnett Shale is really key for growth 2009 through about 2013. I think you'll see us ramp up a lot more activity in those four years versus the early years, Bob.

Another Barnett, if I might. I see that little yellow down there in Somervell County, it looks like that's Tier 2. When would you plan on drilling wells in that Tier 2 area?

Yes, that's -- some of that acreage is pretty close to -- you can't really tell, but really close to Quicksilver's acreage. They're moving towards us. They're being very, very successful. So we're basically shooting seismic now as we speak. So anticipate little to no drilling in 2008 there.

If I might ask one more around the world there, Tunisia, what kind of exploratory work in '08, perhaps in Aniga or BEK, outside of where you've been drilling so successfully, any wild cats in those two concessions?

Every Tunisia well we drilled this year, believe it or not, in Jenein Nord has been an exploration well from an accounting standard. We did not anticipate being seven for seven. We're going to probably do some drilling in Aniga. We'll also extend the boundaries of Jenein Nord in all directions in 2008. We're going to step out slow, be really careful, and primarily make sure we drill [bumps].

Thanks. I'll get back in line.

We will move now to Jeff Hayden with Pritchard Capital Partners.

Hey, guys. Not to beat a dead horse here, but jumping back to the Barnett Shale, with this acquisition, could you give a little more color on the additional 37,000 gross acres in the expansion areas, kind of what counties those are in? What's your working interest there? And then I thought it was asked, I think I missed the answer -- what's your royalty on this acreage?

I'll let Tim -- I'm turn it over to Tim or Bill Hannes. You want to say anything else over and above what I've said?

Yes, the additional acreage we picked up is really in counties -- Erath County, Bosque County, those type counties that as you know, there's been mixed success in those areas and we're kind of watching, sitting back and seeing how that acreage develops. The royalty is as you would expect, in the -- across this with so much acreage that we picked up is -- it's different across all of that but an average, I'd say it's around 80%.

Okay. And any drilling obligations on kind of that 37,000 non-Parker acres? Lease expiration issues? Anything like that?

Well, yes, we did pick up -- I mean, there will be expiring leases and we're going to manage that. We don't anticipate any substantial expiring leases in the next 12 to 18 months, so we feel like we've got that pretty well under control and can balance that within the budget we have.

Okay. Great. Thanks a lot, guys.

Our next question will come from Rehan Rashid with Friedman Billings Ramsey.

Good morning, Scott.

Hey, Rehan, how are you doing?

Good, good, great quarter.

Thanks.

On the leverage front real quick, what is it net, after the acquisitions that were announced this morning, please?

I think pro forma third quarter, we're about 46%. With proceeds from Canada and also from the MLP, we'll be around 44 to 45 at year-end. And we're targeting -- we still have a target between 40 and 45% long-term and maintaining financial flexibility.

The target is 40 to 45%.

Yes.

Going back to Tunisia real quick, on the -- could you remind me again what's the [3P] upside or call it the resource potential there?

Our last posted number was over a year ago. I think we only posted about 50 million barrels. It's significantly above that. We have not given out an updated number. We're working on the gas project condensate. Typical size of a project that we drilled this year has been from like 2 million barrels, 3 million barrels on the low side up to 20 million to 25 million barrels on the upside. So we do have a substantial number, much, much higher than our 50 million barrels we posted over a year ago.

Got it. Okay. Last question on Edwards Trend. Maybe if could you walk us through how '08 and '09 could look like in terms of both drilling activity and reserve bookings and I remember a Tcf kind of 3P potential on this front. Could you maybe give us a feel for what's been the progression in figuring out some portion of that?

I think our last -- probably about two, three quarters ago we gave a range of about 150 Bcf to 350 Bcf discovered. And that excludes the two recent discoveries which are in the 25 Bcf to 75 Bcf range. Those two recent ones, we are moving towards our number of getting closer and closer to a half Tcf of resource potential with more upsides. We'll continue to see growth. As Tim mentioned, the new frac isolation pack, or [frac jobs], are working very well. So we see it growing significantly over the next three years.

Do you anticipate most of the bookings this year, next year, '09?

We had a good amount in last year. We'll have a good amount this year. We anticipate -- it's pretty much pro rata. There will definitely be a good amount in 2008.

In terms of tax implications, you mentioned in your presentation that Barnett was lifetime exchange. How about Spraberry?

No, it was not, due to the size of our MLP, the Petrogulf transaction and the Barnett Shale transaction will cover lifetime exchange.

Okay. All right. Thank you.

We will now move to John Herrlin with Merrill Lynch.

Yeah, hi.

Hey, John.

Three quick ones. How many wells do you expect to be drilling in the Edwards trend next year? Ballpark?

Yes, Tim, what's our latest number?

Number is in the neighborhood of 30 to 35 wells.

With reserve bookings you gave us a sense of what your finding costs were on the percentage of the adds. Could you break them down by different play type?

It's pretty much scattered among those four areas. Of the four, Tunisia and Spraberry are your two biggest adders, followed by Edwards and then Raton. I would rather give out exact numbers in January, John.

Okay. That's fine.

Based on pricing, any pricing changes.

That's fine. You've been doing some more workovers in recent quarters. Should we expect that trend to continue?

Tim?

We had a very intensive workover campaign this summer, specifically in several of our core areas. If you see the slide that Rich has shown over there, slide 23, it was up to about $0.85 per BOE and then $0.83 in the fourth quarter. Typically those are our two big quarters for workovers, tends to come down in the fourth quarter if you look historically.

Just wondering if there was a change. Last one for me. In the past you have mentioned other kind of germinal CBM projects. Any sort of updates with any of those projects?

Yes, John, where it's continuing to watch our Uinta/Piceance project, specifically Columbine Springs and the Castlegate, Lake creek. We have essentially finished all of the drilling and all of the construction of the pilot projects in these areas and we're going to be watching here at the end of this year into 2008, for well performance. Right now, having completed the drilling, we can take a look at the dewatering and therefore the potential increases in gas from these areas and make some decisions as to where we go. 2008 is a year we should see the results and make some decisions.

Thank you.

We now have a follow-up question from Robert Christiansen with Buckingham Research.

Question on the Edwards again. How many exploratory wells in 2008 do you contemplate there?

Chris, you got a hand on that?

I'd say probably around five exploratory wells out of that 30.

And how many did you drill this year? I'm just trying to -- looks like two or three maybe?

Yes, two or three, that's right. Remember, Bob, this year was the year we said we're going to hold off on exploratory drilling while we get the 3D done and some new areas where we're going to focus on development drilling in areas where we had 3D with the idea of making sure we're taking our best shots when the 3Ds have been available.

You said 45% of the 900 square miles was in. Any preliminary indication, anything number of prospects kind of peeking up at you?

It's hard to say number of prospects but I'll just say in some of new areas where we've gotten the 3D, we're seeing things that look very positive.

And one final question, I hope it's not taken the wrong way, but some customers have been recently asking me about Iraq and Pioneer venturing into Iraq, maybe like Hunt ventured into Iraq. Would you care to comment on that?

Yes, we have not been into Iraq or we're not looking at starting up something in Iraq at this point in time. Security has to change significantly, Bob.

Thank you.

For us to even consider it.

Thank you.

Sir, we have no further questions. I would like to turn it back over to you, Mr. Hopkins, for any closing remarks.

Thanks for joining us on the call and please if you have any follow-up questions, give myself, Scott Rice or James [Meyer] a call today.

This does conclude today's audio conference. Thank you for your participation and have a wonderful day.