先鋒自然資源 (PXD) 2005 Q4 法說會逐字稿

Good day 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 Power Point 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 web site select investor and then select investor presentation.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Security Litigation Reform Act of 1995. These statements and 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'd like to turn the conference over to Pioneer Chief Executive Officer, Scott Sheffield. Please go ahead.

Thank you. Good morning and I'm going to go over the first slide, Slide Number 3, and give you an update of strategic initiatives followed by Tim Dove and Rich Dealy to go over reserves of operations report and our financial for the fourth quarter. On Slide Number 3, to update on our billion dollar share repurchase program we've completed about 641 million, about 12.5 million shares and we have purchased a little over 21 million shares since we closed the Evergreen transaction.

An additional 350 million share repurchase program will be initiated once we announce the successful completion of both the Argentina and the Deepwater Gulf of Mexico assets. In regard to Argentina, due to the level of interest after we announced that we were going to sell Tierra del Fuego, we had a lot more interest than expected and ended up signing an agreement for the entire set of assets in Argentina, with Apache for 675 million expected to close at the end of the first quarter or very early second quarter of this year. Most people know bids were due on our Deepwater Gulf of Mexico asset divesture in early January. Negotiations are under way and we hope to announce something by the end of February or early March.

Our 2006 capital program, obviously, is being developed to reflect the reallocation of Deepwater Gulf of Mexico and Argentina Capital, primarily to North America on shore drilling both development drilling through all of our key areas in our new Resource plays, primarily in the Rockies and South Texas and along the Gulf Coast. Obviously, we're very excited about that and we will be releasing all of that detailed information, returns upside on all of these plays on March 9, at our investors and analyst conference, it will be in Dallas, beginning at 7:30 a.m., in the morning on March 9.

I will now turn it over to Tim Dove to go our reserves and our operation update.

Thank you, Scott. This morning Pioneer reported audited year-end reserves for 2005 of 987 million BOE and that's almost 90% North America, 50% gas, and about 62% proved develop. Once again we're one of the longest reserve to production ratio companies, about 15 years at the end of 2005. Netherland Sewell continues to audit our reserves and 82% of our reserves were audited by Netherland Sewell in 2005. If we were to exclude Argentina assets as well as those in the Deepwater Gulf of Mexico that are targeted for divestiture, those numbers would be 92% of total value and 93% of total reserves that were audited by Netherlands Sewell.

At year-end our PV10 value for prove reserves was about 10.3 billion using the SEC standards of about $61.00 oil and $10.00 gas. Turning now to Slide 5, a little bit more detail regarding reserves and finding costs. We added a net 80 million barrels in 2005. That reflects having added reserves of 127 million BOE partially offset by downward revisions of about 47 million BOE's. Of the acquired assets added, about 80 million BOE are attributable to a bolt-on transaction mostly in the Spraberry field that we announced last year very successful transaction and very good optics and metrics on that transaction. In addition, we had 47 million BOE of drill bit additions. These were primarily in our recently announced the sanctioning of the Southcoast gas project in South Africa, our Raton drilling program and then in Canada, our two key drilling areas being the Chinchaga and the Horseshoe Canyon CBM play. In terms of the downward revisions of the about 47 million BOE there's a couple categories that were attributable. One is to Argentina and the other is to Raton.

In Argentina in terms of last years drilling campaign, we were going about the process of developing our deep gas play in the Neuquen basin and the results of that drilling showed more compartmentalization more complexity in these reservoirs than we originally thought. If we then go back and allocate the additional cost it would take to produce these reserves we consider them uneconomic based on where today's constrained gas prices are in Argentina and there for, it's led us to recategorize those reserves that we previously considered proved into unproved categories. In the Raton area, we have additional production decline history on wells and that coupled with unexpected drilling results especially in the north area of the field has led us to downward revised the Raton prove reserve number by about 23 million barrels on a BOE basis. Number of the wells that were drilled on the northern side of the field encountered less coal bed methane by virtue of the fact that the coal was intruded by volcanics in the area and basically was replacing the coal interval, and that has led us then to adjust the numbers accordingly. The table at the top of Slide 5, gives you a recap regarding our reserve replacement percentages and finding cost numbers. Our net reserve adds as I mentioned 80 million BOE resulted in a reserve replacement number of 118% for 2005 which was lower than our three and five year averages which have been roughly 250%, and this is reflective of a relative limited number of successes in our high impact exploration programs for 2005 as well as the downward revisions I discussed just a minute ago.

In addition, it also of course does not include any of the benefits from successes we have that we were unable to be booked by SEC standards and those would be successes in Clipper, Thunderhawk and Zurich, as an example and if you calculate out the net potential for those three in terms of future reserve bookings they would add up to a range of 80-195 million BOE. Those bookings to come in the future are related to those projects going to further development. Our capital for the year 2005 total about 1.3 billion, about one billion of which was used for exploration and development activities and the remaining 300 million of course was for bolt-on acquisitions in our query as much as like I mentioned in the Spraberry field area. As a result our finding and development cost for the year was 15.98 per BOE and this again is higher than our three and five year numbers, more in the nine to ten range. We obviously were impacted by limited bookings from our exploration program and the downward revisions but this higher finding and development cost number also reflects the fact we were experiencing cost creep in many of our areas, the result of the effects of higher commodity prices.

We also show in the table the numbers without Argentina both the reserve replacement and finding and development cost numbers. As you can see our numbers do improve materially if the contributions from Argentina are excluded over the same time periods but particularly for 2005, given the negative reserve revisions I mentioned that we experienced in Argentina this past year and without Argentina, the Companies planning and development cost would have been 12.32 for BOE.

Turning then to Slide 6, talking about really where we're going, vis-a-vis reserves growth, it's important to note that our strategic initiatives in and of themselves we believe will facilitate reserve growth and have the effect of improving these numbers in the future. One thing is clear and that is when we go ahead in the future with our new strategic initiatives, we will be re allocating the moneys that were other wise going into the deepwater Gulf of Mexico and Argentina into lower risk repeatable onshore North American plays that we think can add both reserves and production on a very economic basis, and so we think our reserve replacement and finding development costs accordingly are going to be positively influenced but that will be only through time. And as shown on the slide, we're making substantial in roads in these plays where we have now can claim 400,000 acres having been added in North America in 2005 alone, each with substantial reserve potential for the future. The key is that we're now going to be looking to the new places some of which I'll discuss and talk about in more detail today to positively impact our reserve growth numbers and finding cost numbers as we move ahead.

We also benefit of course because we have some existing assets and existing discoveries and projects we're working on that will benefit from in the future as their reserves are added and those include the Southcoast gas project as we get it on production and can potentially increase prove reserves and as we look north to Alaska and the Oooguruk and Cosmopolitan projects. We also are working very hard on and expect to be successful in further bolt-on acquisitions in our core areas this year and I think that can be a significant contributor in 2006 in the future as we try to replicate transactions of the type we completed last year in the Exxon Spraberry Deal and although much of our development drilling targets prove reserves, we will be seeing a positive reserve additions, in relation to this development drilling campaign as we ramp up development drilling in 2006 in response to what really are excellent margins in our business.

What I'll do now is turn you to Slide 7, where we're getting more into an operational review of where is this reinvestment going to go? Where are the Resource plays and commercialization projects, which are anticipated to add the production reserve growth in 2006 and beyond, and this is really in response to and is really the key focus on our strategic initiatives that is the reallocation of capital to these higher return North American growth opportunities. I plan to go around Slide 7, in a clockwise fashion so we'll start in the northwest with Alaska where obviously extremely pleased to have sanctioned the Oooguruk project that was announced a few days ago. I've got another slide to cover that in more detail. We have commenced the drilling of three north slope exploration wells and those wells are being drilled with our Arctic Fox special purpose rig and the first of which is being drilled, it is directly adjacent to and south south Prudo Bay unit, onshore the slope. Cosmopolitan continues to have a lot of interest to the Company. We have shot the 3D and it's being evaluated now, this is the oil discovery off of the Key Nay Peninsula the Cook inlet. What we're trying to do in the next couple of quarters is evaluate potential conceptual design concepts that would lead to a possible development of this field and we anticipate making a go forward decision by mid year 2006.

Going to Canada, in the northeast BC area where we have our winter access only drilling area in the north, we have three rigs running there and have planned about 50 wells this winter and have gotten a good start. The weather has cooperated such that we have about 40% of our program drilled to date. In CBM, we're following up on what was a very successful 2005 in our Horseshoe Canyon campaign and we'll have two rigs running there drilling a 200 well Horseshoe Canyon program for 2006, and in addition, we will be doing some work in terms of horizontal drilling of Manville CBM to understand the technical aspects of that play and where it can go on our acreage there north of Calgary. In terms of Permian, I think everyone who has followed our company for a long time knows this is a key growth area for the Company. It's going to be key as we look into the future with substantial number of locations we have to drill. We will be ramping up the rig count.

We currently are at 10 rigs but anticipate going into the neighborhood of 12-14 rigs during the second quarter and then up to roughly 18 rigs as we get into the third quarter. And drilling at 350 well program is basically twice as many wells as we drilled in 2005 and it's in response to these very strong margins that we have in our industry today. We also are working in the Spraberry, in another area but it's in relation to our current drilling campaign and that is Deeper [Wolf Cap]. In our new drill well specifically, we are selectively isolating the lower Spraberry Reservoir, [Wolf Cap] which we believe can enhance the productivity of the Spraberry wells themselves or the Spraberry drill wells and it also gives us substantial recompletion potential when it comes to the existing well bores in the area so this is an area we'll be evaluating very heavily in 2006.

In the canyon area, south of the Midland area, we are regenerating activity in the Strawn and [Wolf Cap] camp plays and in the [INAUDIBLE] and Canyon Field areas and there again in the Permian basin. We have an active leasing program acquiring acreage in this play and we see a lot of recompletion potential in a lot of existing well bores and we're going to have an active drilling campaign there this year. We've had some favorable results in terms of early drilling. We plan about 15 wells in this area, and the key here is very quick on production, so I think it could have an impact on 2006 production.

We continue to add Spraberry locations and opportunities for drill to earn in that field. In fact, we've just completed a 200 location addition from one of the major oil companies in the field, basically acquiring drill to earn properties, we'll be drilling several wells on those properties this year and for several years to come and in this area where we have such a dominant position, we're acquiring more acreage in our key units and for that matter in all extension areas in order to build even a bigger presence in this basin. In the Gulf Coast Area we're extremely excited about our South Texas Edwards expansion play. I've got another slide in a couple minutes we're going to talk about that. We'll be adding a couple two or three rigs in that area to begin the expansion of that project.

In the onshore north Louisiana and Mississippi area, we have a relatively large acreage position there, about 67,000 gross acres we are a party to and we'll be drilling what appears to be about 20 wells in the Hosston Cotton Valley play and in fact, the rig in question will be arriving there in mid February so we're excited about that developing into a potential growth area for us. Finally when it comes to the Gulf Coast area, we will be operating an onshore deep northrup test mid year in an area in play where we have about 23,000 gross acres. On the shelf, we had a five well campaign that completed early this year and we drilled four discovery wells out of those five. We are considering various development scenarios and evaluating next steps really with the shelf assets including their possible divestiture. That's in light of the fact we are under current negotiations on the deepwater Gulf of Mexico package and I would anticipate a decision on the shelf properties by year-end.

Now, switching to the Rockies, we have a substantial Raton program under way again this year, about 300 well program. That's following up on the 290 wells or so we drilled in 2005. We continue to see a gradual pick up in production and actually the drilling campaign this year as opposed to what we suffered in 2005 is actually ahead of schedule. We have several activities in the Uinta/Piceance area where we have about over 300,000 gross acres and I'll just summarize a couple of the activities here. In Uinta, we have the coil tubing drilling rig, Evolution Two, which is a Pioneer rig, drilling a horizontal reentry in the Castlegate field, this is deep coal test, and in addition to, which we have a couple of other CBM pilots as well I'll talk about in a minute but also we have an Entrada sand gas test that we've drilled and we also are planning further drilling based on 3D in that field. In the Piceance, the Columbine Springs CBM pilot is continuing to do certain activities and we are some what waiting on weather before we can get in there and complete the two pilot program that we planned for this year plus about ten in field wells. We're very excited about the Lay Creek CBM pilot and that will be the subject of a future slide as well that's in the sand wash basin there north of Piceance and it's one of these areas where we think we can reinvest substantial amounts of moneys in a growth project.

In all of these areas we're continuing to add acreage but the real key is here you've got three projects in Castlegate, Columbine Springs and Lay Creek and we're trying to get to year-end to evaluate the performance of these to decide whether we launch a substantial development in these areas. That should be enough on that slide I would say so let's move to Slide 8. Again, we're very excited about the Oooguruk project sanction that was announced recently and this of coarse is on the central north slope of Alaska in shallow state waters about four to five feet of water and we're the operator of this project and very happy to have completed the sanctioning of it, based on receiving all of the necessary permits only late last week. E&I of course is our partner here. This is a substantial project. The first aspect of it involves laying a six acre gravel island production facility and we are under way with that process as we speak and hope to have that done this winter. If we're able to complete that this winter then next winter what we would be doing is putting in place the off shore and onshore flow line installation as well as the off shore facilities and equipment installation and then at the end of next year, begin development drilling and development drilling is a process that takes a couple years really into even early 2010 before it's all done. We're drilling,substantial number of 40, in fact 40 long reach horizontals up to 7,000 foot laterals, and the tie-in will be back into the Kuparuk River unit facilities via sub sea flow line. It is a very long life project and we're very happy about that and as I mentioned before it has substantial Resource potential and all of this is unbooked today so very happy about having the Oooguruk sanction and moving ahead we've got an outstanding team of people in Alaska working on this project.

Let's go to Slide 9. This is the first of two of the what I'll call preview slides that we have in this presentation in terms of the preparation for the analyst conference on March 9. The news here is that we are substantially expanding our presence in the Edwards trend where we're the largest operator in the trend and we think the trend expansion is going to provide us a significant upside. To refresh your memories here, the Pawnee field which has been a long- time Parker and Parsley and Pioneer field is in the middle of a trend. It's a tight gas, limestone reef reservoir that is part of a trend that extends some 250 miles, through Texas in a relatively thin band of several miles wide but nonetheless 250 miles long. This if you were to look at it from a satellite photo looks analagous and identical to the current [Beliefs] reef. We'll be showing you interesting photos at the analyst meeting in that regard.

The real key to this though is our understanding in an application of technology to substantially increase recoveries and production from this field. We have more than doubled recoverable reserves from the field by introducing horizontal drilling in the field. What's important though is most recently, we have been acquiring acreage so as to expand the things that worked at Pawnee over this expansive 250 mile area where the Edward trend resides , and we have have 170,000 acres now in hand, and we'll be adding to that as we look in the future but we essentially now control an area that we believe has 24 prospects along trend to hopefully be able to replicate the same kind of success we had at Pawnee. Toward that end, we have drilled the first exploration well in this expansion as of the end of last year, that well is making about 1.3 million a day. That's the Schultz Number 1 well. We have a developing plan or a development plan that's substantial here in terms of incremental drilling, 20-30 wells planned for 2006 and we've already drilled the first well and it's waiting on completion. What we're doing of course is leveraging that horizontal drilling expertise in this area that has made the Pawnee field grow so substantially. We have two rigs in the field today. We will have two more rigs, three more rigs that are actually being constructed and we will use to execute the plan, the first of which will be in the field in March. And the key here is if you look at the extensive nature of this play where we control essentially all of the acreage, we think the Resource potential exceeds one TCF. So we're very excited about the Edwards trend expansion and we think it can have a significant impact from a production growth and reserve standpoint looking ahead.

On Slide 10, this is the second of the preview slides, if you will. It's regarding the Lay Creek project and we have the question; Is this ex-Raton? It's one of the things we're trying to do in our company is provide opportunities to add several new Ratons. This project is north of the Piceance base in and the sand wash basin in northern Colorado. It's an analog to the work that Anadarko been doing in the Atlantic rim CBM field north some 20-25 miles of Lay Creek. Interestingly, you have even better coals here at Lay Creek than you have at Raton. More coal and as a result, more gas in place. The person working on this for us is Dennis Carlton, many of you know Dennis in relation to his work with Evergreen and the Raton field expansion and he's going to be the instrumental guy in providing the technical assessment and the way forward on Lay Creek, so we have a lot of confidence that we have the right guy working on this project. We operate this and have 50% interest in it. The real key is coming into an existing area where pilots have not worked. We think with our expertise in Evergreen and CBM in general we can fix these pilots because we believe the gas is there and the coal is there and the key is to isolate the coal seams and reduce water handling. The exact things we have done in Raton, and the earlier reviews are good. We have two wells that we have reentered and have excellent permeable coals and we're in the process of testing those wells.

We also have two to three pilots planned ourselves. In this area, these are new pilots we're going to construct and what we're doing of course is leveraging the Raton technical capability. We are going to bring the evolution to coil tubing drilling rig, the one that I mentioned is over in Castlegate and after we do it's work there it comes over here and drills five wells immediately in Lay Creek so we're also utilizing our own rigs here and our own crews to basically get the benefits of the knowledge and technology advantage we have in Raton and apply it here at Lay Creek. This is an area that's relatively easy to work in in the sense that the majority of acreage is within or outside a federal land I should say, state lands, makes it easier to get permitting done relatively quickly.

As I mentioned in relation to both Castlegate and Columbine Springs, this is a project we are trying to bring to fruition with the work were doing this year so we can sanction a large development at the end of 2006, if this works, and if it does, just like the Edwards expansion, it has greater than one TCF resource potential. On Slide 11, just a summary slide on Africa.

The West Africa campaign has begun with the first well this year in block 256, that was spud in January, and in addition , we have completed our 3D seismic acquisition in January in block 320. These are areas of course that can give us, we believe, exploration optionality and upside. Tunisia is going to be an area of increased activity in 2006 where shooting seismic in the atom concession and we have had eight successful wells and never drilled a dry hole and we're trying to learn more about how to expand that area vis-a-vis this 3D seismic shoot. In addition we are going to ramp up drilling. We are currently planning two but perhaps going to three rigs and even up to about 11 wells depending upon success. Some of the wells incrementally will be dependent upon success in the early drilling campaign.

South Africa, we have a subsequent slide on South Africa but we're very happy to announce earlier this year the final sanctioning of that project, the Southcoast gas project and we have spudded the first of the development wells and Sables continues to be an excellent oil project and exceeding production in terms of our plan versus our budget. And then on Slide 12, that Southcoast gas project with a little more detail. We are certainly pleased to have concluded the sanctioning of this project. It is an important project in terms of the growth and gas production that gives us in the second half of 2007. We have 45% interest in the project and again it is bringing gas from existing gas discovery sub sea back to the FA gas platform for delivery on to the beach to the Mossel Bay Synfuels plant and it has substantial impact from the standpoint of production as well as we think it will ultimately have more potential for reserve bookings. The current contract we have written which features gas rises tied to oil prices, only goes through 2012. The fields in question that will be developed as well as other fields in the area could add even further to the reserve base. We think the ultimate recoverable reserves on a gross basis in the area of this development is 3 to 500 BCF.

With that, I'll pass it to Rich for discussions of the fourth quarter results.

Thanks, Tim. Starting on Slide 13, I'm pleased to report that the earnings for the fourth quarter were $141 million or $1.08 per diluted share and income from continuing operations was 140 million or $1.07 per diluted share. As we disclosed in our last call, the fourth quarter results do include a $47 million gain associated with the sale of our [Gabon] assets. Operating cash flow for the quarter was $372 million and discretionary cash flow increased to $412 million up 17% from the prior quarter. The increase is primarily due to higher NGL and gas prices that we achieved during the quarter. As I briefly go through the next few slides regarding the fourth quarter, you will see that we are not providing first quarter guidance related to production, operating costs, or other costs and expenses as has been our normal practice. We are deferring providing this information until early March when we expect to have further clarity regarding the outcome of our Gulf of Mexico asset divestiture process. Turning to Slide 14, oil and gas revenues were $622 million for the quarter, representing an 11% increase over the third quarter, and as I mentioned the increase is primarily attributable to higher NGL and gas prices plus increased production during the quarter. Turning to Slide 15, production for the quarter was 171,000 BOE's per day as compared to 169,000 BOE per day for the third quarter.

Gas production declined 2% as compared to the third quarter primarily as a result of a curtailing production from our Falcon wells in order to fully recover gas reserves associated with the Raptor Satellite field in the Falcon Corridor. This decrease was off offset increased gas sales in the Raton field as a result of the CIG pipeline expansion being completed in early October. Oil production increased 6% during the quarter, primarily due to Devils Tower production being resumed, once repairs were completed on Chevron's Empire Terminal which has sustained significant damage from Hurricane Katrina. I think it's important to note also that the Devils Tower production loss while it was down was covered by business interruption insurance and the Company expects to recognize about $20 million or recover $20 million during 2006 associated with that down time.

Turning to Slide 16, where we show production on geographical basis, you can see that African production is down for the fourth quarter, which is primarily the result of reduced oil cargo lifting in South Africa. Canada and Argentina production is flat with the third quarter and as I mentioned earlier, U.S. production for the quarter was up primarily due to increased Raton field and Devils Tower sales offset somewhat by the reduction in Falcon sales.

Turning to Slide 17, oil prices for the quarter were down 4% reflecting drop in NYMEX oil prices during the quarter. NGL prices increased 8%, reflecting increased demand for ethane, butane and and propane during the quarter and gas prices increased 18% as a result of substantial increase in gas demand during the quarter. Specifically, North American gas prices excluding the deferred revenue amortization with our three VPP transactions we did during 2005, increased to $7.88 per MCF, roughly 19% over the third quarter amount.

Turning to Slide 18, fourth quarter production costs were down slightly from the third quarter to $7.55 per BOE. As you can see from the slide, production taxes for the quarter increased quite a bit primarily as a result of the higher NGL and gas prices. If you look at LOE, LOE for the quarter decreased, principally due to Devils Tower operating costs being largely fixed in nature and so we had the fixed cost that were relatively costs from the third or fourth quarter but had substantially higher production from Devils Tower once it resumed production in November and when we were able to add the Triton and Goldfinger wells shortly after the Devils Tower production started back up. The second reason for the decrease in the fourth quarter really reflects the third quarter was higher than normal due to it including miscellaneous repairs and start up costs associated with the same gas plan in the West Panhandle field which had been down as a result for a fire for part of the second quarter and third quarter.

Moving to Slide 19. Fourth quarter general administrative costs were consistent with third quarter $33 million. Interest cost for the fourth quarter increased to $35 million as a result of the increased borrowings associated with the $641 million stock repurchases that we accomplished since announcing our strategic initiatives on September 1, and rising interest rates associated with the borrowings on the Companies credit facility. D&A costs for the fourth quarter were $8.68 per BOE consistent with the third quarter.

Cash income taxes for the quarter were $19 million, principally attributable to cash taxes in Tunisia and the U.S. Given our U.S. NOL position, U.S. cash taxes were principally related to alternative minimum tax and tax on the additional repatriation of foreign earnings that we did during the quarter. The Companies overall effective rate for the fourth quarter was 41% and is primarily attributable to an increase in the tax rate in Tunisia going from 65% and the permit nature of certain non-deductible seismic costs we incurred in foreign jurisdictions principally in Nigeria.

Turning to Slide 20, exploration and abandoments during the fourth quarter were $83 million, dry holes, the dry hole component of that was $23 million, and was primarily associated with an unsuccessful well in the Gulf of Mexico Falcon area and unsuccessful wells in Argentina. G&G expenditures were $28 million for the quarter and are principle related to seismic activities that Tim mentioned on Cosmopolitan and Alaska and the Piceance area in the Rocky Mountains and internationally in Nigeria.

Delay rentals, unproved property abandonment and other, includes $7 million in incremental abandonment costs associated with the loss of our east Cameron 322 platform as a result of Hurricane Rita. As you may recall, we recorded 33 million of incremental abandonment cost in the third quarter associated with this loss and during the fourth quarter we had increase that estimate based on additional information and revised cost estimates. While we expect insurance to cover the entire incremental plugging cost as well as the lost revenues out there, the accounting literature does not allow us to recognize that today and so we had to book the abandonment cruel with no offsetting insurance recovery. We do expect that insurance recoveries will be recognized as they become better quantified and known over the coming quarters. The bulk of the remaining costs relate to unproved lease hold abandonments and related costs in the U.S, Argentina and Africa.

Turning to Slide 21, costs incurred for the fourth quarter were 303 million. This primarily represents our ramping up of our core area development drilling in the U.S. And exploration activities in the U.S, Canada, Argentina, Tunisia and [Nigerium].

At the back of this presentation we've included supplemental schedules for your reference, those schedules show the detailed components of discontinued operations, quarterly oil and gas volume and deferred revenue amortization associated with our three VPP transactions, the Companies current commodity hedge position, historical long gas price differentials by a geographic area and detail of year-to-date income taxes.

Hopefully you'll find those helpful in your analysis. That concludes my comments. At this time we would like to open the call up for questions.

Thank you. [OPERATOR INSTRUCTIONS] And our first question comes from Brian Singer with Goldman Sachs.

Good morning.

Hi, Brian.

With regards to reserve bookings given the timing of the development work and the exploration in Edwards and the Rockies do you believe you'll be able to book meaningful reserves from these areas at year end 2006 or are these nor likely for 2007 and following up on that if we look at some of the development drilling in north America in ' 06, are there enough probable locations that can more than replace the pud locations that you're drilling?

Yes, Brian. I think I really focus all of these reserve bookings, Tim mentioned and future reserve bookings from Edwards and Raton and so on,, we're looking at a three to five year trend to be in the top quartile of our piers groups, so, not necessarily everything is going to be, booked in 2006, were looking at the next years to be in the top quartile of our pier groups, so it's going to be spread out over that five year time frame.

And then in terms of the development drilling, whether it's Spraberry or Raton, are you mainly drilling puds this year and if so, are there more than enough probables left to replace that or should we just expect that the production growth will mainly come from pud drilling?

Most of the drilling is in pud, but the same time, we are adding a lot of drilling transactions such as the deal with the major oil company in Spraberry, we're adding a lot more acreage in Raton so you'll see a combination of adding new extension drilling in puds and also, drilling puds. If you recall, our policy in Spraberry trend area for the past several years, we have drilled over 3,000 wells and we have never booked anything to extension. It's all been through the acquisition lease hold category. So even though our drill bit finding cost has been high, we never had one Spraberry well in the extension category, so we do it through lease hold acquisitions. We will continue that aggressively acquiring new locations in both Raton and also Spraberry, along with drilling puds.

Thanks. One question on Edwards, could you talk about how you get to the one TCF of resource potential, is Pawnee included in that is that just representing the 170,000 or so acres that you have acquired in the last year and just give us a sense on the total number of locations and resource for locations that might be out there to get to one TCF.

Pawnee is excluded and the one TCF is conservative and you'll see more detail on March 9, and with it will show higher numbers than the one TCF.

Thank you.

Next we'll hear from Bob Morris with Banc of America Securities.

Good morning.

Hi, Bob.

On the one TCF that you mentioned at Edwards and Lay Creek, are those gross or net numbers?

Those are gross numbers.

And what is your interest on average at Edwards then?

Edwards it will be 80-90% depending on which area and Raton it's 50%, I mean Lay Creek it's 50%.

Okay, did you mention a budget for 2006?

No. We have not but we have commented that it's very similar to the budget number that we have spent for 2005.

Okay, and then lastly, you mentioned a decision on possibly selling the Gulf shelf assets by year-end. Why not sooner or do you think it will take to year end or is that just being conservative?

The primary reason is because we had the four recent discoveries that's taken the time to work-up the development nature of the discoveries and we think we think it enhance the package and that work won't be completed until this summer, and so that's why Tim mentioned something about year-end orderly 2007.

Okay.

There's also an abundance of shelf properties in the marketplace in the first quarter.

Okay.

Of this year.

All right great. We'll see you next month. Okay.

Thanks.

Now from Sven Del Pozzo with John S. Herold.

How are you doing?

Fine.

I'd like to know, how much experience have you had in 2006 drilling in field wells in the Raton? The last I understood is that you were going to be drilling some on 80 acre spacing.

Yes, Sven? Actually, most of the drilling that we're doing and if you refer to in field drilling as drilling the fifth and sixth locations in the sections, not the eighth as you would refer to there.

Okay, so, how much in field well drilling have you done during the year?

Well you mentioned 2006. I assume you mean 2005?

Oh, sorry I made a mistake then, 2005.

Well the drilling is a combination of in field drilling as well as extensional drilling as we work out, work the play outwards so it's a combination there of.

What percent of the -- my last two questions also relate to Raton. I'd like to know what percent of Raton was developed at year-end and also I'd like to know if you could give us an exit rate of production there.

Seriously, the question what percentage of the development, like a question regarding future probables.

What percent is proven is developed?

Oh. I don't know the answer to that. Do you know the answer to that?

I don't know off the top of my head.

We'll have to get back to that one, Sven.

And the exit production rate?

We'll be talking about that in our March 9, conference, so I will refer you to that conference, please come down and we'll give a lot more details in that regard.

Okay!

We'll now hear from Ross Payne with Wachovia Securities.

Hi. Can you give us an idea about what kind of reserves may be involved on the shelf that may be divested?

I think we probably think of it more in terms of current production, Ross, being about 3,000 BOE per day, relatively short life properties.

Right.

That's excluding these recent discoveries obviously

Okay. I have a flip back yet but I'd jump on here a little late. On Alaska, any kind of expectations on what kind of reserve, total reserve potentials there?

This is in terms of Oooguruk, Cosmo, or what are you referring to?

Both.

Well, I think in the presentation we mentioned the potential in terms of the Oooguruk reserve potential and were right now in the process of evaluates Cosmo so it would be earlier for me to comment as to where we thought that would come out, we're also are drilling some exploration wells, as you may or may not have heard that could potentially add reserves here in the short-term as well.

Okay I'll look at the presentation for that. Also in Argentina, are there any rights of first refusal in that situation? Do you expect any of those to be exercised?

There is a right of first refusal that applies to the southern assets, it's too early and we certainly wouldn't want to speculate on as to whether they would be exercised.

Okay. And do you want to throw out any figures on where you see F&D moving down to 2006?

I think long term, we're in a $60 price environment and obviously probably at $8.00 gas price environment and I would expect the industry is going to move toward the$15.00 to $ 20.00 finding cost range. Our three and five year goals is to be a top quartile leader in that range.

All right! That's it for me, guys, thanks.

Thanks, Ross.

Next we'll hear from Gil Yang with Citigroup.

Good morning.

Good morning.

Could you comment on Argentina? You mentioned that you didn't book the reserves there because of the price environment there. Could you give us an idea of what price would make those reserves economic?

We didn't. Well, yes, the downward revisions were due to the deep gas play.

Right.

They were moved over to 2P.

Okay.

A lot of those in the probable and possible category and we had excellent results two years ago. We drilled a lot of wells in 2005 that offset some very good wells and obviously we noticed that the -- something changed, permeability, porosity, faulting and those reserves have been shifted over to the 2P category. Obviously it will be up to Apache to decide what to do with that going forward.

But you can't give us, I mean you mentioned in the commentary that it was more complex and more expensive to produce than today's price. Do you have any sense for at what price they become economic ?

Well the average gas price is a $1.00, so it's back to a risk question. Do you want to be drilling on higher risk deep gas wells? You're getting somewhere between a $1.00 and $1.25 for it. And that's one of the reasons why we're getting out of Argentina. We decided not to.

Okay. On the subject of risk, you commented I think I forgot the exact number but 189 million barrels that you had sort of in the pipeline that you expect to book up over the next few years. Can you give us an idea of the specific visibility and risking that you'd put on it? Is that sort of 90% chance that will come on line or is there still a substantial risk it's not all that reserve well will be proved up?

Well, I mean, this is different for different projects, right? A couple of these I mentioned were Gulf of Mexico projects that we believe have a high probability they will be taken in [truism] in terms of development, and here I'm speaking specifically of Clipper and and Thunder Hawk. Oooguruk, we already sanctioned that project, very high otherwise we wouldn't be spending the money on it this year. You have Cosmopolitan out there which would be substantial and it is still the subject of engineering evaluation so it's early days, but I think the key is we've got several of these types of projects in the pipeline, including some of the new things I mentioned at Edwards and Lay Creek, among other areas that I think we will be able to contribute.

And maybe another way of asking that question; Of that amount that you're talking about how much would you consider to be sort of in the bag, [crude] versus P2-type reserves.

Well if it was [proved] we would have booked it.

But some of it is already the Oooguruk type that is provable, right?

That's correct but let me just say of the projects I mentioned we have sanctioned one, that is Oooguruk. But it would be th closet to what you are referring to something that was a more kin to proving although wer can't by SEC classification standards consider it proved today.

Sure. Last question is South African gas project can you just remind me is that a PFC or not?

It's basically a royalty tax regime. Very, very low royalty that royalty there is .75%, tax is about 35%. Best economics in the world.

Okay. Thank you!

We'll now move on to Robert Lind with Simmons & Company.

Good morning everyone. In the Edwards trend, what is the average well cost there?

It's in the neighborhood of approximately $3 million. It can be upwards of four depending on the circumstances as to the horizontal and lateral.

With the three new build rigs, how long is your term for these rigs?

Anticipate those to be three year terms.

And estimated time to drill, horizontal here?

Well, the vertical well bore takes about 14 days to drill , and the lateral takes about similar amount of days I guess roughly so it's about one month wells.

Okay, and then at Lay Creek, what is your average well cost there?

We're guessing $400,000. We don't have that number right in front of us but $400,000.

Correct.

Okay, and how many locations do you plan to drill per section here? And is it like 60% recovery gas in place?

Well, I mean, the answer is this is why you do pilot projects because you have to establish the productivity of these wells and the ability to flow gas. I mean suffice it to say we're drilling several pilots each of which is several wells and basically each one of these pilots has a water injection well. It has a monitoring well and four potential producers, so we'll get a lot of well control from these. If it works, of course, you have a substantial number of potential locations several hundred locations would come out of a development of acreage this size if it were to work.

Okay, gentlemen. Thank you that's all I had.

Thank you.

We'll now hear from John Herrlin with Merrill Lynch.

Following on the Edwards question was that a dry hole cost or completed well cost?

That's completed well cost. We really don't drill dry holes out here.

That's fine. What about the split between fracing and drilling?

We don't frac the wells, John. The drill a vertical well bore, kick it off into a horizontal lateral, open hole some 2,500 feet, throw a little acid on it.

Okay. You do acidize. That's fine. Raton? You guys sounded surprised about the volcanics appearing. Had you run straight wells in this region where you had the issue with the puds?

No. We knew that the issue of intrusive was there, but we did not know the actual extent of it until we drilled wells. I think we were surprised at the amount of intrusive, not that they were there.

Okay, that's fine. And then you did sell assets as well so you were in kind of a liquidation mode this year on reserves. Should we expect the same kind of thing and also with respect to the reserve adds, what was the deepwater contribution, can you say? In 2005?

I think, yes, we added very little in deepwater because Clipper and Thunder Hawk have not been booked.

Okay.

And in regard to their contribution, I think we've released that, it was was 50 million 2P and it was up for sale and that roughly half of that is proved.

I was just wondering if there was any changes. Super. Thank you.

Not really.

Thanks.

We'll now hear from Joe Magner with Petrie Parkman.

Good morning. I was wondering it looked like you booked the reserves in the south coast gas project that were booked and in the presentation it shows 220-240 B's of recoverable in the initial project. How much of that was booked in 2005?

We booked, pardon me?

11.

11.2 million BOE we booked as is the practice in Pioneer we're relatively conservative in bookings this is about the P80 reserve level.

Right. Okay and then the last question about the reserve, the unbooked reserve potential, looked like Clipper was a 50 million barrel pre-drill, Thunder Hawk is 50-150 and Oooguruk was 50-19. Those were gross numbers.Based on your splits does that get us to that what I think is 80-105 is that the number you mentioned in terms of unbooked potential?

Yes.

And then are Clipper and Thunder Hawk included in the deepwater package?

Yes, they were in our data room.

Okay. You mentioned that the basin there was a gas test drill. Has that been completed or do you have any results for that?

We reentered one well in our Entrada area and had in conclusive results but encouragement at least so this will lead us to drilling more wells especially after the completion of the 3D seismic acquisition out there.

One follow-up on Lay Creek. It's my understanding there was an existing CVM project up in Lay Creek. What do you or what have you sort of learned from the results of that and how do you expect to sort of improve things or what do you plan to do differently going forward up there?

Well the prior operator, we believe, made some or could have been improved upon as to his technical handling of the project. The key is in this area I think I mentioned this earlier in my comments, you must isolate the individual coal seams and frac those individually much like it's really been the key in Evergreen successor Raton. In this case, the fracing was not as successful and as times they were fracing into water leg so they were creating massive water handling problems and this is obviously the key in these projects is getting water off the coals and being able to dispose of it. They did not have the proper amount of water handling and we're not isolating and individually fracing the coal seams and accordingly they were getting results they didn't understand. We look at all of this from a technical standpoint and say this is something that's easily understood in the context of the history of Raton and believe we will create a situation where we can in essence fix their existing pilots and drill our own so as to get comfort by year-end where this project goes.

Okay, thanks, and then I think [andarko] they mentioned that they wrote off their [anagede] block in Tunisia. Does that effect your plans for that area going forward?

Yes. In regard to that, [anagede] we still feel like there is potential there, and we are continuing to evaluate them and our position in that play.

Great. That's all I've got. Thanks.

We'll now hear from David Tameron with Jefferies. Good morning.

Everything has been beat to death here but one quick question follow-up. Who is your partner in Lay Creek? You're the operator; correct?

Santos out of Australia.

Okay, thank you.

We have time for one last question.

That question comes from David Heikkinen with Pickering Energy.

Yes, this is Marshall Carver actually. What kind of a decision to exit the joint development area off shore Nigeria?

Yes. We could not come to an agreement with our partners basically on several agreements.

Okay. That's it for me, thanks.

Okay. Again thanks. I'm looking forward to seeing everyone, , on March 9. We've sent out that notice here. We have a dinner the night before on March 8. I think the important thing is you'll probably see a lot less of Tim, Rich, and I and you'll see a lot of our asset managers come in and make most of the presentations, detailed economics, of those projects and while we're spending money, the reasons why and look really at a 3-5 year picture of the Company going forward. Looking forward to seeing everyone there and again thank you very much for attending this call.

That does con cloud today's conference call. Thank you for your participation.