先鋒自然資源 (PXD) 2007 Q4 法說會逐字稿

Good day, everyone. And welcome to Pioneer Natural Resources Fourth Quarter Conference Call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the internet at www.pxd.com. Again, the internet site to access the slides related to today's call is www.pxd.com. At the website, select 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 in the most recent public filings on forms 10-Q or 10-K made with the Securities and Exchange Commission.

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

Hey, everyone. And thank you for joining us. I'm going to briefly review the agenda for today's call. Scott Sheffield is going to be the first speaker. He's going to go over the financial and operating highlights for the fourth quarter and for the year 2007. He's then going to comment on the company's 2008 capital budget and our outlook for strong production and cash flow growth in 2008 and through the year 2011. After Scott concludes his remarks, Tim Dove is going to review the performance of our key assets during 2007 and provide some expectations as to what to look for in 2008. Rich Dealy will then cover the financial highlights for the fourth quarter and will review our earnings guidance for the first quarter of 2008. After that, we're going to open up the call for questions as usual.

Before turning the call over to Scott, please let me remind you that on January 8, we announced that an amended registration statement was filed with the Securities and Exchange Commission for Pioneer Southwest Energy Partners Limited Partnership, the master limited partnership that we plan to form for the purpose 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 this MLP and any other MLP plan. As a result, we do not plan to take questions related specifically to the MLP in this call or in follow-up meetings. We refer you to the press release and registration statement for further information.

With that, I'll turn the call over to Scott.

Good morning. We are starting out on page number 3. I'm pleased to announce with Pioneer had one of its best quarters and best years in 2007. We reported fourth quarter 2007 net income of $205 million or $1.72 per diluted share. We had a clean number of $0.99 per diluted share and adding back Alaska PPT had a clean number of $1.10 per share. Fourth quarter productions continue to grow, 103,000 barrels a day equivalent. We're up 12% above fourth quarter 2006. Our four key growth assets: Spraberry, Raton, Edwards, and Tunisia are up 18% versus fourth quarter 2006. For the year, we produced 35.5 million BOEs, 14 on a per share base, production per share growth, 14%. Reported all-in finding costs for 2007 of 1540, reserve replacement of 357% with a PV-10 of about $13.4 billion, that using year-end prices of 96 and 680. You get to the same number using a price deck of 85 flat and $8 flat. Continue to repurchase shares at opportunistic times during 2007, we bought back 4.9 million shares during 2007. We did have a successful Canadian sale, closed that in fourth quarter with proceeds of $540 million and recognized a gain of $101 million. The recent run up in gas hedges, we've added another 70 million of gas hedges just for the year 2008. We now have 200 million hedged at a swap of about 842 NYMEX.

Slide 4, operationally, some key things are happening obviously over the next several quarters. Obviously, we're very pleased with what's happening in the Edwards Trend with our recent announcement nine discoveries to date. We've increased our resource potential from 400 to 600 BCF, having the largest discovery in the Edwards Trend in over 30 years with a significant discovery which Tim will talk more about. The initiated production from the Jenein Nord block where we've had several discoveries in Tunisia. Again, Tim will talk more about that in a ramp-up of production all during 2008. We also initiated Oooguruk development drilling, which will continue over the next three years. We expect first sales in our Alaska project mid year. Another growth project will be growing significantly on top of our four growth projects that we mentioned earlier. We closed attractive bolt-on acquisitions in Spraberry, Raton, and Barnett, adding 140 million barrels of oil equivalent resource potential in over a thousand drilling locations. The MLP obviously for market conditions has been postponed and timing is uncertain. We continue the MLP market downturn as temporary we believe. Longer term, we expect it will be an attractive market for MLP based on the growing appetite for yield especially obviously in this lower interest rate environment. Pioneer's long life assets are good MLP candidates and 90% of the company's proved reserves are MLP. Also, it gives us an opportunity to make acquisitions at a much lower cost of capital.

Turning to Slide 5, delivering consistent production growth. It shows after the sale of deepwater in Argentina and Canada, what the company looks like on a pro forma basis, continue to grow consistently for 2005. The growth rate has continued to pick up significantly and going to 2008, 2009, and so on. We delivered 14% production per share in 2007 and we'll continue to grow at our established rate of 12% over the next several years.

Going to our FND and reserve goals, Slide 6. We announced all-in finding costs of 1540, drill bit finding costs of about 1785. If you exclude our Spraberry and Raton pipe drilling, it's about $12 per BOE, reserve replacement of 357 %, PV-10 of $13.4 billion and that's footnote at the bottom using roughly 96 oil and 680 gas. Also, you get to the same number I mentioned earlier at 85 flat and $8 gas flat. Our proved developed number is 9.7 million and our PUD number is 3.7 billion. Audited year-end proved reserves 964 million BOEs, up 10% from 2006 excluding Canada. We added 130 million barrels of oil equivalent primary from Spraberry, Raton, Edwards, and Tunisia and recent acquisitions in those three areas that I mentioned already. We do have 86% of our reserves audited by the top world engineering firms that does audits. Reserve mix, 97% U.S. We are 51% gas, 49% liquids. Our proved developed continue to move up from 60 to 62% over the past year, and that number will continue to move up. Still have one of the longest RP ratios at 23 but that will be coming down over the next four to five years. You can see each of our key areas in the table that at up to 964 million. Spraberry is about half the company at 481 barrels, Raton 266, and so on. We seen a big jump obviously with our success in Tunisia and also the addition of the Barnett Shale since last year. Total resource potential has picked up in several key areas, adding up to 790 barrels of oil equivalent.

Slide 7, our 2008 capital budget as we announced a couple years ago. 2008 would be in line with cash flow, it is. It's at a billion dollars, 40% reduction really focused on our four key growth areas that grew 18% over the last 12 months and adding on top of that with our Oooguruk development drilling that just started. Primarily, most of it's development drilling with some into the resource place.

Slide 8 is an update on our returns on our 2008 drilling program. We basically seen in a couple of our key areas. We basically have had some of our cost come down from last year , especially in stimulation and [see many] cost. And in addition if you look at the big change from the last time, we had this slide out. It's probably more oil-related projects especially Spraberry Trend area. Obviously, Tunisia is still an infinite IRR what's going on there and Spraberry has increased significantly with a 2.1 [DRI] at 85 and 8, and a 1.7 at $70 oil flat and $7 gas. So, that's probably your biggest change is the economics in Spraberry are continuing to increase significantly and that's reflected in the value of our PUDs which are primary Spraberry Trend area PUD value.

Slide 9 essentially no change there. What we talked about in the past continued to deliver 12% per share, growth over the next four years through 2011. Obviously, we've added and Tim will talk more about it our Cosmopolitan project which we're excited about in Alaska with the recent test there, and obviously with the recent acquisition in the Barnett Shale in the resource column, with a lot of upside going into that area, drilling several hundred locations over the next four to five years.

Slide 10 really shows the additional upside of our legacy hedge explorations, the combination of oil hedges, the VPP, essentially all hedge also. So essentially, this is the reduction of our oil hedges primarily over the next four years and shows incremental. The bottom incremental cash flow pick up will be picking up 200 million a year in 2009, additional hundred million in 2010, and additional hundred million in 2011 with a 400 million pick up. When you combine this slide with the slide of growing 12% production growth on a per share base, we'll be delivering 20% cash flow growth rate over the next compounded over the next four years from 2008 to 2011. 65% of that revenue growth is from oil-related production growth. Also, as mentioned, we'll be free cash flow neutral in 2008 and significantly positive free cash flow in 2009 to 2011. Return on capital employed will be doubling over the next four years also, primarily due to the fact of the underwater oil hedges rolling off. So again, we're excited about the growth doubling cash flow over the next four years and combination of growing production and with the hedges rolling off.

Slide 12, investment highlights. Obviously, we're on track to deliver 12% production per share through 2011. We think we've proven it with our feet, four key growth assets: Spraberry, Raton, Edwards, and Tunisia growing 18% over the last 12 months and adding on top of that our Oooguruk project will come on midyear and growing significantly over the next three to four years. Obviously with that, we'll be achieving 20% cash flow growth through 2011. Production growth primarily from high margin oil-related projects and also obviously as mentioned already includes the benefit from the rolling off of oil hedges. We now have an inventory of over 6,500 locations and we will continue to expand core areas attractive bolt-on acquisitions as you have seen over the last two to three years. In addition, we'll have significant free cash flow through 20 11 as we had back in our periods. As we develop deepwater, we had significant free cash flow back in 2002 to 2004. We're back in that same period over the next four years. So obviously, we're very excited about what 2007 has accomplished.

Let me turn it over to Tim

Thanks, Scott. I think if you look at our operations results in 2007, you come to the conclusion we really showed solid contributions from all of our core areas in terms of production and reserve growth as well as value additions and first, of course, and foremost is our Spraberry resource play that's shown on Slide 13. It continues to be a tremendous foundation asset for the company. It's still maintaining the percentages it had last year about 25% of last years production and about 50% of proved reserves. We added reserves significantly about 9% net of production to the point now where we have about 481 million BOE proved reserves about 50% of that is, of course, PDP. And because of a couple of positive transactions, one specific transaction will be closed in the fourth quarter. We've added net drilling locations during 2007 as well. Production was up substantially in 2007 about 13% compared to the prior year and we think that 2008 will be approximately about a 15% growth rate compared to 2007. Our drilling rate in terms of rigs, about 16 rigs under operation today. We'll drill about 350 wells. That's about the same number of wells as we drilled in 2007. We were very -- we benefited substantially I should say from the acquisitions we closed in the fourth quarter as I mentioned about 38 million BOEs of resource potential added for about $90 million of capital, so exceptionally strong economics, especially considering upper 80s WTI prices. And we continue to benefit from new applications and technology, specifically deepening wells in the Wolfcamp where we can add about 20% incremental reserves as compared to the old traditional way to drill Spraberry wells. So all in all, an excellent year and I think the case can be made for many more good years to come from this oil resource play.

Turning then to Slide 14, excellent execution this year by our Raton team, especially on CBM throughout 2007, especially given the fact that they had such a slow start in first quarter due to the snowstorms early last year. It's still a substantial asset for the company, about 30% of our total production and 25% of reserves. Again, in this core asset, we added reserves to the [tune] of about 6% net of the production in 2007 to 266 million BOE. It's about 65% proved developed. And we have maintained a large drilling inventory of 2P locations as well. Production, as I mentioned, came back and met the plan we had in place for 2007 at about 10% growth, which is a great tribute to the team in catching up from that slow start. We think 2008 will grow a similar percentage, a little over 10 %, mostly because of the work that was done in 2007 and I'll comment on that in a minute. The fact is though we're also the beneficiary during 2007, specifically regarding getting mid-continent gas prices as compared to having to take Rockies prices which are substantially lower during 2007. So, our economics certainly benefited from that. We did put on production about 300 wells last year. Some of that was catching up on inventory wells that were waiting to be put on production so we dramatically improved our efficiency in the field and you'll start to see the benefits of that in 2008 as all of those wells are on production. In addition to which, we plan to complete about another 175 wells during 2008 and that's what gives us confidence on about a 10% plus growth rate. We're happy to have completed in the fourth quarter the transaction that's added net resource potential of a substantial amount in the Raton, CBM play as well. We continue to be an industry leader when it comes to an integrated well services model where we can control costs in the field about we continue to have a lot of upside to optimize around compression so as to boost production, not just from drilling wells but from optimization of compression at the field and at the wellhead.

So Slide 15 then, Scott already alluded to great success in Edwards. And as you know, we put a recent press release talking about some of that success. But overall, production is up about 38% in 2007 versus the prior year, and we think we'll be up about 25% in 2008. We drilled about 34 wells and expect a similar number of wells in 2008. And importantly, Scott alluded to this a minute ago. We've made substantial head way in improving up resource potential by drilling new discoveries and new field discoveries in the Trend to the point where that's up about 250 BCF to about 400 to 600 BCF on a gross basis of resources that we believe we proved up from new fields that have been discovered. And one specific discovery that was made in the third quarter last year, actually now done further appraisal drilling is probably one of the largest fields discovered over many years, about 150 BCF or so in the Trend. And importantly, some of the new completion technologies were applying have resulted in very substantial increases in well test rates. Of course, these well test rates aren't necessarily indicative of long-term production capabilities of the wells. But nonetheless, they show an indication these will be strong producing wells with enhanced EURs. And three of these wells, each tested in the range of 12 to 16 million cubic feet a day so it gives us a lot of confidence as we look ahead as these wells will be tied in during 2008. If you look at our fourth quarter production, it was essentially flat in the Trend at about 62 million cubic feet a day. What's happening there, of course, is we are drilling some of these wells out in areas where there's limited infrastructure so we have several of the wells even today that are waiting on new facilities to be built out to their locations. We believe that as we get into the first quarter and the second quarter, many of these wells will in fact be tied in so we anticipate especially as we get further in the year. We'll start to see the effects of tying in some of these very positive wells. In addition to which, of course, 2007 and 2008 were big years for 3D seismic shoots. We're about 50% done and anticipate being fully done by the end of 2008 and that, of course, is critical to the proper imaging of the Edwards Trend potential and for that matter locating future wells.

Okay, Slide 16 then is on Barnett. Of course, we're just cranking up our Barnett activity as a result of acquisitions that were made in 2007. We put an excellent team together whose goal is to make this a core area for Pioneer. And toward that end, the acquisitions added about 80 thousand gross acres and substantial number of drilling locations and resource potential as shown on this slide. We probably will participate in about 20 wells. Some of which will be in a partnership with Devon and Wise County and it will be operating our first well in the Trend ourselves, spudding here in March in Parker County which is really the main area of our focus in the Barnett Shale. And so, we're starting to get cranked up. I think the case is we ramp up drilling. We'll be hitting our stride in 2009 and 2010 and this asset will have significant impact of Pioneer in those years beginning 2009 and in 2010 as we increase the rig count.

Slide 17 is on Tunisia. Of course, we had substantial success in Tunisia and it's continuing. Production was up about 65% in 2007 and we still anticipate an 80 to 90% growth rate as we get into 2008 and that's coming from the fact that the we've had a substantial number of new discoveries, specifically in our Jenein Nord block as well as some additional discoveries and appraisal wells that were positive in a couple of other blocks. We'll drill about 15 to 17 wells next year or this year I should say, 2008. And we are completing what our important 3D shoots in some of these key areas, Jenein Nord and Anaguid to the north which are really required to accurately image and optimize the drilling locations as we go ahead. Importantly, we're making progress on our Jenein Nord production facilities. We just began production late 2007 with one well and what you'll see in 2008 is we'll gradually increase production through the year. We'll be ramping it up progressively based on putting new facilities in place. Effectively, we're not constrained by well-productivity. We've got substantial positive wells to tie in from time to time. However, it will take us time to build the tankage capacity and facility capacity so as to substantially increase production. So, you'll see even though today, we are about 3,500 barrels a day gross from three wells. We'll be ramping that up as we get into the year. And as shown here, capacity will go to about 10,000 barrels a day once we get into the third quarter, and about 20,000 barrels a day. This is on a gross basis by the end of this year. So basically, it gives us confidence that this 80 to 90% growth rate is doable especially in combination with [atom] production. And of course, 2008 we hope it is a year where we can make end roads into the gas project which will have us taking gas from the southern blocks in Tunisia up to northern markets.

Slide 18 is on South Coast Gas in South Africa. We initiated production as many of you know in late 2007 from our South Coast Gas project. Current production is about 3,500 BOEs per day on a net basis and of course, that includes only four current wells. We have one well which has an umbilical leak which is being tended to. It's going to take some time to get that fixed. But the bottom line is we are still withholding production from our best well. There's one well in this field that is currently an injector of gas in the Sable oil field that represents about 90% of South Coast Gas proved reserves and of course, some of the Sable oil field life has been extended substantially longer originally planned because of high oil prices. It now appears more likely than not we're going to start producing both Sable oil and gas simultaneously after facilities are put in place at the end of 2008 and into early 2009. That will substantially increase the total rate of production from this project. And of course, we are benefiting from high oil prices which are reflected then in the gas prices in this project as well as the condensate produced as well.

And Slide 19, our Alaska Team really did a phenomenal job in 2007, putting our facilities in place and our rig in place and getting ready for the activity of 2008. We are doing the final commissioning on our production facilities as we speak. Drilling is under way. We're happy to say. And the rig is performing very well. We've already drilled our disposal well. We've got two cup C producer wells and one injector to drill here between now and mid-April, let's say. And first production anticipated being during the first half of this year and sales of course which is the basis upon which we can count actual production anticipate midyear. About 3,000 to 4,000 barrels a day net by the end of the year, reaching peak production 15,000 to 20,000 barrels a day in 2010. Still substantial resource potential obviously, 70 to 90 million BOE on a gross basis just for the Oooguruk accumulation but there are also expansion opportunities. actually, some within reach of the current island and others in surrounding areas so this will be a place where we continue I think to add reserves and add production.

Scott alluded to the Cosmolitan result that are shown on Slide 20. Of course, this is something we've been discussing for some time, the reentry of an existing well bore to test a new horizon. This was a resource that was discovered actually in the 70's. It's a couple miles off the Kenai Peninsula. We drilled an extended reach horizontal undulating well from an existing well bore to test out this reserve potential somewhere between 30 to 50 million barrels gross. Pioneer today has 100% of this block. The results of course were pre-indicated on. Number one, we had a long term test in the hemlock which is one of the horizons back in 2003 and these results here we're working more on another zone called Stariski. And the important news is we believe we have established production capabilities from this Stariski zone itself in the neighborhood of 400 to 500 barrels of oil per day and we think that in combination with the prolific hemlock tests earlier a few years ago will lead us to an economic development that we can pursue here in the Cook Inlet based on today's oil prices. Of course, what's needed now is our permitting to take place and we need to do our facilities planning during this year, we'll probably drill one additional well. Probably, solidifying our knowledge of the hemlock productive capability early 2009 and then it would be after that we would be considering the sanctioning of the project, so very good news on Cosmopolitan. It's the type of project that can be the next resource play in our Alaska division. So, let me stop there and simply say 2007 was an outstanding year operationally for the company and I think we're looking forward to even bigger and better things looking into 2008.

And with that I'll pass it to catch Rich for a discussion of the financials and the guidance for next quarter.

Great, thanks, Tim. And good morning. Scott mentioned net income for the quarter was $205 million or $1.72 per diluted share. Included in net income are five significant items listed on Slide 21 here where I'm at and those in the aggregate increased quarterly results by $89 million or $0.73 per share. With the exception of the Alaskan petroleum production tax refund, the second item on the list there, all of these items were previously discussed in our December press release where we announced unusual items that would impact the fourth quarter. So adjusting for these items, we continue to be pleased as Scott and Tim both have mentioned that the financial results of the company are continuing to improve, production is growing, and as you can see, cash flow is expected to increase substantially in 2009 and beyond.

Turning to Slide 22, discussion of come out it prices. You can see on the green bars there that our oil price realizations increased 12% relative to the third quarter as a result of the rising oil prices. Somewhat offset by legacy hedges that we talked about earlier that will expire at the end of this year. NGL also was a benefactor of higher oil prices increasing 21% quarter on quarter, and gas prices were flat quarter on quarter but you can see we did benefit from our in the money gas hedges that we have in place.

Turning to Slide 23 on production costs. Production costs for the quarter were down slightly at $11.82 per BOE and part of the significant item I mentioned there in the ad valorem tax. We have accrue ad valorem taxes throughout the year. In the fourth quarter, we get the bills in. Those bills came in a little bit less than what we were projecting on an accrual basis so the ad valorem tax results are down for the fourth quarter reducing our operating production ad valorem tax category there. If you look at base LOE, you can see the base LOE, it's been flat for the past three quarters essentially and so the team has done a good job of managing those costs and rising oil price environment.

Switching gears to first quarter guidance on Slide 24. Daily production for the first quarter of 2008 is expected to be 103,000 to 109,000 BOEs per day. Production costs are consistent with the fourth quarter at $11.75 to $12.75 per BOE. Expiration and abandonments are projected to be 40 to70 million. As Tim mentioned, this is primarily comprised of drilling and seismic activity in the Edwards Trend and Tunisia areas. DD&A and G&A are consistent with the fourth quarter. Interest expense, we do expect to be down relative to the fourth quarter primarily due to the reduction in LIBOR rates that we've seen over the past month as well as the refinancing that we completed in January. Cash taxes are expected to be $10 to $15 million as principally Tunisia which is the only significant area that we're paying cash taxes and our overall effective tax rate for the first quarter is expected to be 40 to 45%.

Turning to Slide 25. We give a listing of numbers supplemental schedules that are in the back that you, guys, have seen for the past quarters. So I'd encourage you to look at those but at this point, that concludes our prepared remarks so we'll open up the call for questions.

Thank you. Our question and answer session will be conducted electronically. (OPERATOR INSTRUCTIONS) Our first question today will come from Brian Singer with Goldman Sachs.

Thank you, good morning.

Hi, Brian.

A few questions on Edwards Trend. First, can you talk to what you think is driving the improved initial production rates that you've seen in your last few wells?

Yes. It's a combination of better porosity, better [permeability] in the recent prospects, in the [reef], combined with the Packers Plus technology.

And if we look across your acreage position, I guess where are you seeing these higher rates? Is it concentrated? Is it diversed? Can you kind of talk to you where you are in terms of what you drilled up over your acreage position?

Yes, I mean, our rates initially without Packers Plus initially started about 3.5 to 4 million a day two or three years ago, with experimenting of Packers Plus, some got up to 6 to 8. And the recent discoveries, we're starting to see obviously rates between 12 and 16, so I would anticipate that probably closer to half, maybe half of our resource potential is going to have the better rock, so it's still very economical at 4 to 4.5 million. It will just make these recent wells even more economical. So, this large prospect that we discovered, we've only drilled probably about four wells on it. So it could, we have significant drilling to do on the next two or three years.

Okay. And have the wells that you've drilled and the good rates that you're seeing then in various parts of acquisition or are they relatively concentrated?

No, it's pretty much throughout. Even in Pawnee, our original field with extending the Packers Plus, we've seen some 8 to 10 million a day rates initially. So it's pretty much half to three quarters. We're going to see the higher rates.

Great. You got a few numbers with regards to Edwards resource of proved reserves of about I think 228 or 230 BCFE, and then a gross resource potential, you've proved up about 400 to 600 BCF and then a net resource of 100 million BOE and 600 BCF. Can you kind of talk to what goes into each of those numbers ?

Yes. It's basically -- it's all based on since we have our 3D seismic coming in. So, it's based on initially you have a discovery. Secondly, we've had appraisal drilling in almost all of our prospects now. We try to define the limits and then you combine that with the 3D seismic and that's how we come up with it. So a very detailed process.

Okay. And so, what is in the 100 million barrel or 600 BCFE of resource that isn't in the discovery gross resource potential of 400 to 600 BCF?

We have additional prospects. It's probably the main difference. We have several more prospects that are on Trend or next to existing discoveries, and that's all been with recent identified 3D seismic. We'll be drilling several more low-risk exploration projects over the next two or three years, Brian.

Okay, thank you.

Our next question will come from Ellen Hannan with Bear Stearns.

Hi, good morning. I just had a couple of questions. One, I was curious as to whether or not you've made any changes in terms of how you book reserves this year in terms of revisions versus extensions, which has been something of a debate I guess among some other companies in the industry about whether in-fill drilling is an extension of a field or a revision, if you could comment on that. And the second one was with the change in the South Africa oil versus gas, could you give us maybe an idea of your production outlook for this year in terms of the split between gas and liquids?

Yes, in your first question on reserves, we haven't changed. If anything, the only change is that we have added. We're continuing to book all Spraberry leases that we pick up that are adjacent to an existing well. We book them as proved undeveloped. A lot of companies will book those as extensions, so as in the Barnett Shale for instance. So if it's an adjacent to a proved developed location and we pick up a lease, we will book it as a PUD. We have had some extensions in the Spraberry Trend area, the first time ever in the company's history and that's primarily that we are buying acreage into this Wolfberry play and we've made some much better Wolfcamp prospects or discoveries. And so if we drill a second location away during the year, we have added some probables in the Spraberry Trend area. So, there's not really a change of practice at all, just that we are getting some Spraberry for the first time in the company's history, primarily due to this Wolfcamp extension so we are drilling some locations that are two steps out primarily due to the Wolfcamp.

South Africa, you're really not going to see -- it's pretty much going to stay about 50/50, between liquids and gas, up until we bring this well on. It's capable of producing 80 to 90 million a day. It will probably start at about half of that by the end of the year. Right now, I think Tim alluded to this. It's probably Fourth Quarter and what will happen is the Sable oil will essentially be shut in for a period of time for about three months to four months, five months, and it will come back on flowing and we're hoping to move off the FPSO. So, you see a significant drop in operating cost so where essentially the goal is to flow the oil, the condensate and the gas from two wells to the platform and you will see a significant increase in production. It will be more gas-oriented starting in the -- so, gas may get up to 75% of the production starting in first quarter, second quarter of 2009.

Great. Thanks. And if I could just back up for a second I meant to ask you about the potential in the Wolfberry as opposed to the Spraberry or Wolfcamp that you alluded to. Can you give us an idea of what you may be looking in terms of that, in terms of your resource potential or is it too early to say?

There's a couple areas that we are moving into the Wolfberry that we're getting more than 20% as Tim alluded to. 20% is the standard rule of thumb for picking up reserves in the Spraberry Trend area by drilling another thousand feet deeper. We have certain acreage that we are getting more than that and we're just now assessing it. So, it will probably take us another six months to a year, Ellen, to really get a handle on how big it is.

Great, thanks very much.

Our next question will come from Gil Yang with Citigroup.

Hi.

Hi, Gil.

Hi, Scott. What's your success rate in Edwards?

Yes, 82%. I know we've drilled two dry holes and over the last three years, so it's 80 to 85%.

Okay, so it's nine -- the success that you've mentioned basically you drilled nine wells and you had nine hits?

Yes, I guess it's nine discovered so nine out of 11. Whatever that percentage is.

Okay, and to get the higher rates, how much more are you spending on those wells than before that's not really a big deal?

During the year, we spent about a million dollars per well and we're experimenting with during 2008 and 2009 whether or not we can get the same results for less. Stimulation bids did come down and so our goal is to get the million dollars cost down.

Is that the total cost?

Yes.

Okay, for the Packers Plus.

You have the additional cost.

Okay.

A million dollars for Packers Plus.

What's the total cost of these wells including that million dollars?

They're running about $5 to $5.5 million per well.

Okay. Can you talk about the source of the negative gas revisions in your -- for the year for your bookings?

Yes. Basically, it's minor areas in -- I think a combination in Africa and also in probably in our UP area, Uinta and Piceance area.

Just based on performance?

Performance or higher operating cost.

And then finally, for Tunisia, how much do you have to spend to develop those discoveries and are those discoveries I guess those discoveries are part of the 24 million barrels or so you booked in Africa?

Yes.

How much more do you have to spend on those to develop them up?

We're basically just building the tank batteries going up to 20,000 barrels a day, and that's basically a small piece of our capital expenditure. I think Tunisia has roughly 150 million capital budget this year and that's a small -- very, very small piece of the budget.

Okay, so you can produce out of the discovery wells?

Yes.

All right, thank you.

Our next question will come from Leo Mariani with RBC.

Yes. Good morning here, guys. Quick question on your Tunisia oil production. I noticed it was down a little bit in your fourth quarter roughly about a thousand barrels a day from the prior quarter. Just trying to get a sense of what was going on there?

Yes, it's really primarily due to sales. We're going to have that fluctuation during the period. So, we could produce a lot more but due to liftings we have to move the oil to the coast. We sell it to primarily E&I and so our liftings are going to vary versus actual production.

And also, Leo, I didn't mention this on the call but we did have some unexpected work overs in the Adam concession that dropped some production during December, so that had the effect as well in addition what Scott mentioned. But those wells are now back on production.

Okay, so what's your current Tunisia oil production now?

You could take that number plus the number that Tim gave you for 3,500 roughly so roughly half of that. Net of the Jenein Nord plus 3,500 to 4,000. So, you're up in the 5,500 barrels a day, but as I said, first quarter or second quarter, you may sell 3,500 to 4,000, or you may sell 7,000. And so Tunisia is going to fluctuate significantly between sales and actual production.

Okay.

I know it's hard for us model, too. We model production versus sales and then we give ranges. We get first quarter guidance or any quarter guidance. We try to get a rough handle on actual sales. So, it may vary low or high depending on whether or not we think we can get a lifting into each quarter.

Okay, got you. Can you give us a little bit more insight in terms of the government coming into the Jenein Nord session? Is that just for the seven discoveries you had or are they coming in on the block in general? Can you give us a little bit more of the terms there?

Yes, there are several other blocks in Jenein Nord. They came in what we call the "true concession." There was a negotiated concession and it represents probably only half or a third of our acreage potential. And so, we have two-thirds that we're shooting and so when we start drilling on the other two-thirds which we are in 2008 and 2009, if we have discoveries on that then we'll go through the same process to get a -- convert it to a producing concession. So right now , they're only in the [Sharook] going

And in terms of your 2008 drilling program is that going to be focused on the [Sharook] concession or is there drilling outside of that as well?

Combination of both. There will be some on Adam with E&I, some on BEK with E&I, some on Anaguid for the end of the year, and some on appraisal drilling on Sharook with the government. And then, we'll be drilling on other areas in Jenein Nord that do not have a producing concession. So, some of this will be initially 100% Pioneer and Anaguid. Some of it initially will be I think we have 60%, and Anaguid so we'll be spending $0.60 or 60% dollars or 100% dollars until the government elects to come back in. And the Sharook, they will participate in that and we'll be spending $0.50 on that.

Got you. Okay. Question on the Edwards here. How much of your acreage has been tested at this point?

Probably just a small portion. We've got a long way to go on continuing to develop it and expand. 3D is still coming in on a lot of the areas and we're seeing more and more prospects.

Okay. So, would a 25% type of number be reasonable for what you guys tested out there or is that too high or too low?

25%. It could be 20 to 30%.

Got you. Okay, thanks a lot, guys. I appreciate it.

Thank you.

Next we'll hear from Joe Allman with J.P. Morgan.

Good morning, everybody. Could you comment on the cost environment? You've mentioned that stimulation rates seem to be lower here than what the they were before. Which of the service costs are still coming down? Which ones are plateauing, are there any increasing and where specifically?

We pretty much have locked in tubulars back late last year. We seen some pressure on tubulars, we monitor the market, tubulars have been going up but we've locked in our price at much lower same cost as last year. Stimulation seems many have come down and most of our rigs are on contract. They've got, obviously, the same price as last year. So, labor costs have moved up a little bit. So in general, the things are flat to down 5% in general, so.

That's it. And you mentioned some fuel level efficiencies at the Raton. Could you speak to that a little bit, what kind of offsets might you get or what kind of improvement might you get based on fuel level efficiencies? What are you doing to improve efficiencies and what are you budgeting in terms of cost for 2008?

Well, if you look at Raton, the main benefit we get there is from simply an integrated service model across all of the different processes. And about 65% of our total cost is covered by internal type of activities when it comes to operation. So, that's where we get the major cost benefits and so we really don't see any substantial increases in Raton. We do see some benefits obviously in Spraberry because we've been doing a lot of work in terms of building our own infrastructure in Spraberry from the standpoint of providing our own services. So, Raton is going to be pretty much flat. The drilling rates in Raton are essentially flat in 2008 versus 2007 and as Scott mentioned we should see reductions in permitting.

I appreciate it. Thanks.

Next, we'll hear from Rehan Rashid with Friedman, Billings, and Ramsey.

Good morning, Scott.

Hi.

On Alaska, when do you think we should see most of this net resource potential transfer over to proved?

Probably 2008 to 2011. That includes Cosmo also.

Okay, but this Oooguruk maybe 2008 or 2009?

Yes. It will have to do with the number of wells. We're on schedule to drill about 12 wells per year, and a total of close to 36 wells. And so, it's a question of those wells obviously will be proved developed.

Right.

It's a question of how many PUDs you can offset with those. So -- and that will be equally done over the next two or three years.

Is there the [guess estimate] on EUR's per well?

With 36 wells, half injectors, you can divide that into a resource base of roughly 70 to 90.

Okay.

And take off 70% working interest. We have 70% working interest in operates that will give you a rough estimate.

Got you. I'm going back to Edwards Trend for a second. Your CapEx for the year, how much of that is going to go towards Edwards Trend? And based on some of these recent results, is it going to be a shift on which areas within the Trend you focus on?

Yes, I think it's $175 million. So, that's about 17 to 18% of our total CapEx, and we see it staying roughly about the same over the next two or three years.

Okay. And within the Trend, the better porosity, better [perm] is there any reason not to attack that the first?

Yes. In fact, we're waiting. We're purposely not drilling wells in this best area until we get the capacity there. So, we've had four significant discoveries, obviously, that will come on as Tim mentioned by late first quarter and until we get the capacity situation solved, we will not attack it aggressively until later this year.

Okay. So, later this year. Great. And once again, I'm sorry maybe I missed this. Going from 3.5 million a day to 12 to 16, the Packers Plus and better kind of acreage of kind of are driving that. How would you split them, the rate change, would it half and half, better porosity?

The rate chain, well in several, we're experimenting, continuing to experiment with our Packers Plus and in fact, in a couple areas we were getting 4.5 to 5 several wells and all of a sudden, we tested a recent well, 11 million a day, so pretty much in all of our areas we are seeing some 9, 10, 11 million a day rates. The 15 to 16 million a day rates are more in a couple new areas where we have total Resource of 150 to 200 BCF a day or 200 BCF total. So, we're starting to see better rates in all of our areas.

Got it. And the net resource potential of 100 million barrels, what is that based on, your prior experiences or maybe the newer higher rates that you're seeing?

No, it's based on first you got to drill your discovery well and then drill your appraisal and a lot of our appraisals. We know where the 3D is so we're stepping out and trying to define the boundary. So, we're having lots of success drilling on the fringes and so we haven't even drilled in-field wells yet in several of the prospects. So, we're defining the boundaries based on 3D so that's why we're pretty sure about the resource potential.

Got it. But the EURs used, are they pre-Packers? Post-Packers?

Yes. Right now, in our return slide, we're using a fairly low EUR. Since we don't have history, these wells would be like decline curves, so we're not projecting right now a significant increase by tripling the rate. We're not tripling the reserves. We're probably only adding about 20 to 25% incremental reserves right now. There's potential for significant positive revisions and additions over the next several years as we get history.

Okay. That sounds good. Thank you.

There are no further questions at this time. Mr. Sheffield, I'll turn the conference back over to you for any additional or closing remarks.

Okay. Again, we thank you very much. We had a great quarter and great year. We're looking forward to see everyone during 2008. Again, thank you very much.

And that does conclude today's teleconference. We would like to thank everyone for their participation and wish everyone a great day.