先鋒自然資源 (PXD) 2006 Q4 法說會逐字稿

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 two of the slide presentation. And in most recent public filings on Forms 10-Q or 10-K made with the Securities and Exchange Commission.

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

Good day, everyone and thanks again for joining us this quarter. Let me briefly review the agenda for today's call. Scott Sheffield's going to be our first speaker. He's going to discuss the financial and operating highlights for Pioneer for 2006, which was a very good year for the Company. He will then comment on our capital budget for 2007 and our attractive growth outlook not only for 2007 but also beyond that period. After Scott concludes his remarks, Tim Dove will provide some additional detail regarding the 2007 capital budget and then move on and talk about the performance of our key assets both in 2006 and what to look forward to in 2007. Rich Dealy will then cover the financial highlights for the fourth quarter and provide earnings guidance for the first quarter of this year. After that, we'll open up the call for your questions. With that I'll turn the call over to Scott.

Thanks, Frank. Good morning. We're going to start on page three, financial highlights. Pioneer reported fourth quarter net income of about 28 million or $0.22 per share, total for the year, 740 million, $5.81 per diluted share for the full year. For 2006, we repurchased almost 9 million shares at a cost of about $39 per share, which essentially completes our share repurchase program. In addition, we announced another $300 million share repurchase program. We think it's important over time to continue to reduce shares as volatile as the commodity price market and stock prices allows us opportunities to buy the stock cheap.

In addition, with continued high storage, Pioneer's entered into an additional 100 million a day. Gas hedges a little over $8, that was through April through the end of the year. When you combine that with our previous $90 million a day hedge at over $9, we have hedged 170 million a day at $8.60 NYMEX, essentially protect the economics of the gas drilling program, especially with the recent weakness we've seen over the last several weeks in natural gas prices. Pioneer has a strong balance sheet, much stronger than we did year end '05 with a net debt to book of 33% at year-end.

On slide number four, operational highlights, we ended the year 101,000 barrels a day equivalent which exceeded our forecasted rate which we stated out in March. In addition, we ended the year almost 36 million BOE's which is the high end of our range that we gave out almost a year ago. What's more important is the fact that North America is up 12%. We'll hear us more talk about that versus '05. Total PXD was up 7% and that's simply due to the fact that our South Africa, oil discovery Sable has been in decline and dropped about 3,000 barrels a day which is the difference between the 12 and 7%. You'll see later on with both Tim and I's presentation that two of our key assets, both South Africa, will be up significantly in 2007 along with Tunisia.

The important fact is that the growth was driven by Spraberry, Raton, and Canada. We gave the numbers of all low risk development drilling programs, 21, 10, and 18%. We'll continue to see significant growth going into 2007. For the year, we added net reserves of 91 million barrels in 2006. We'll talk more about that detail in a second. Reserve replacement 200%. F&D cost as we had stated between 15 and 20. We came a little bit over $18. We drilled six discoveries last year, very important in our average trend expansion area, high drilling success rate in those and we'll be focused on drilling horizontal appraisal wells in 2007 on those six discoveries. In addition, most of these wells were drilled -- are being drilled in late '06 but we had four new discoveries and a significant appraisal well in Tunisia. Those four wells tested a combined rate of over 13,000 barrels a day. We'll be testing the fifth well in the next two weeks.

Both South Coast Gas and the Oooguruk projects are on schedule. We'll have significant impact in regard to production and reserves in 2007, '08, and '09 with our total asset base. In addition, Pioneer, we expended our lease hold acreage significantly in core areas. A lot of it is in the Spraberry trend area, with our aggressive drilling campaign beginning in late '05, early 2006, and we added a resource potential of 150 million barrels of oil equivalent.

Slide number five, going F&D and reserve goals, as we had stated our reserves of 905 million barrels of oil equivalent, those reserves were audited 89%, by one of the top three firms in the world. We've had significant additions primarily driven by Spraberry, Raton, Edwards trend, and Canada. Reserve mix, obviously with the sale of Argentina, we significantly are focused on North America with 98%, still about the same balance, a little bit more weighted toward gas, 54% gas, 46% oil. The PDP PUD states pretty much about the same versus last year. Our oil and finding costs of $18 and if you look at just North America where we grew production 12%, it's a little bit less than $15 per BOE. We still have an RP ratio of about 20 plus years and you can see the table, the break down and one of the keys, Pioneer will continue to have a very conservative policy. A lot of the reserve growth was in the Permian Basin primarily in the Spraberry trend area where we take step out locations as we acquire through joint ventures, farm outs, and leases, we will always book those toward the acquisition category. So most of the acquisitions that you have seen, very very little production, probably less than 500 barrels a day, mostly acquisitions for step out drilling and we take a conservative policy and book those in the acquisition category versus the extension category.

Turning to page six in regard to where we allocated capital, in 2006. You can see 2006 was a significant reduction in high impact explorations. You'll see in 2007 we're continuing to reduce high impact exploration down to about 5% of capital. South Coast Gas and Oooguruk, two projects will add significant production in reserve growth from 2007 through 2009, we spent $225 million in 2006 it will be a similar number in 2007. We'll be adding reserves in those projects over the next three years of about 50 to 60 million BOE's both having significant upside over and above that. Acquisitions, as I mentioned were primary leases, farm outs, joint ventures, a couple with major oil companies where we have added 150 million barrels of oil equivalent and resource potential. Some of that was reserves that we added for 2006.

In addition, I think an important message is that North America grew 12%. You can see from roughly about 1.2 billion if you back out the acquisitions which is primarily production, on primary leases, production as I mentioned earlier was only about 500 barrels a day. Production grew 12%. If you back out another $100 million really for seismic and some of our non-conventional CBM plays which added little to no production in reserves, we grew North America with about 900 million in capital. So again, to our maintenance capital slide that we've been using just proves that the Company can grow at least 10% per year with about $900 million worth of capital.

Slide number seven, going into 2007 CapEx and goals, you can see the change is really less high impact exploration, moving down to four wells on the high impact exploration, two in Alaska, and two in West Africa. Resource plays will continue. It's primarily the average in Tunisia. We have some for shale gas plays in our core area which Tim will talk about. In addition, another 25% of development projects in South Coast Gas and Oooguruk and then continuing with development drilling. As you look into '08 and '09, what you'll see is that 25% for South Coast Gas and Oooguruk will move more toward development drilling and resource play so you'll see that 70% come on up to about 90, 95%, high impact exploration staying around 5%.

2007 we're confident we'll continue to grow production, 10% plus. That's primarily due to the fact that we grew North America 12. Tunisia is going to increase as Tim will talk about over 30% in production. It was flat from '05 to '06 and South Africa Gas will be up 20% plus where it had a significant reduction due to Sable last year. So that's the reason we're confident we'll continue to grow 10% plus. We have increased our finding and development cost from a year ago. We had a range of 10 to $15. We're now 12 ti $18, that's simply due to the fact that increase in cost was about 20% from service costs that we saw over the last 12 months and so we're targeting 12 to 18 for 2007 and 12 to 18 over the next five years at the current commodity price market of roughly 7.50 gas and about $60 crude.

Going into our production profile that we've had some slight changes. This is on slide number eight over the next several years, through 2010. The important, we came out with a 10% number in March of last year. We're increasing that range 10 to 12%. That's primarily driven by the fact we're getting more and more confident that Edwards and Tunisia will grow significantly. So we've taken a portion of their -- as we develop those assets, some of those assets will move into the blue color, become development, leaving still a significant growth in the magenta color being in resource plays. Resource plays, as we continue to have success primarily in Edwards and Tunisia, and some of our Rockies plays, we have a chance obviously to increase that significantly over the next several years.

Slide number nine really is a slide we've been using just to show strong returns on all of our drilling projects, both development drilling, resource plays throughout the Company, strong cash margins, strong returns, and also strong discounted return on investment projects. Both had a sensitivity case and also at a 60 oil flat and 7.50 gas. Just to remind people on sensitivity case, we are using current well cost in regard to those returns at 50 and 550. We are not forecasting a significant reduction which we do believe if we do get into that environment, the returns would improve significantly on the sensitivity case so we're using today's higher cost structure.

Slide number ten, our 2007 focus, and really goals, continue to grow production with a target of 10% plus. Obviously the fact that we've already established that track record with Raton, Canada, and Spraberry in 2006. We'll continue to focus a lot of the capital on Spraberry and Raton, which grew a combined rate of about 15% in 2006, establish first production, second half of '07, and South Coast Gas and Oooguruk in early 2008. It's also to convert Tunisia and Edwards. Both Tunisia and Edwards were flat production from 2005, 2006 with our ten new discoveries, four in Tunisia, six in the Edwards, both of these two areas will become significant growth vehicles for us in 2007 through 2010.

In addition, very pleased with the fact that we were -- acquired a lot of acreage over the year in a lot of our core areas adding huge potential, resource potential, and about 150 million barrels of oil equivalent. Also, it's important we started several unconventional resource plays, both coalbed methane and shale plays and a lot of our core areas and also the Rockies and adjacent to a lot of our core areas, it's important to advance those in 2007, start showing production, and also reserve bookings from those plays. And finally, we implemented a new share repurchase program as I've mentioned, we think it's important to continue to reduce shares in this volatile market as we see dips in the stock price. Obviously we're confident we're going to deliver again in 2007 and beyond and let me turn it over to Tim Dove to give more detail.

Thanks, Scott. I'll start on slide number 11 by giving a preview of where our 2007 capital budget is going to be spent and first, in the case of slide 11, we're discussing our North American projects, starting in the Northwest quadrant in Alaska, the Oooguruk project is on schedule and on budget and we still anticipate first production in early 2008. I'll talk more about that in a subsequent slide and give you some details as to where that project is. Scott mentioned, we do have a two well exploration program in the NPRA area in Northwest Alaska with our partners Anadarko and Conoco/Phillips and the first of those two wells will be spud next week and a second well spud at the end of the first quarter so we'll be getting back to as we get well into the second quarter discussing the results of that drilling.

We are planning to drill a test well in Cosmopolitan, that's in the Kenai peninsula of Alaska, testing a prior discovery in Cosmopolitan, its existing oil reserves. We're going to be reentering an existing well with an extended reach horizontal to essentially determine productive capability of a second reservoir in the field to then hopefully come to the conclusion as to commerciality of the yield so as to then go to a direct field development. So that will be something we'll be reporting on after the reentry of that well some time in the second half of this year.

In the Rockies, we had just a tremendous year in Raton, in revamping and developing a growth profile in 2006 and we expect that to continue. We'll be maintaining a well program, a drilling campaign in the neighborhood of 250 to 300 wells again in 2007, and we think we can maintain a growth rate similar to what we did in 2006. That said, we did get a slow start in Raton due to some weather issues. That's why we have put the range here at about 7 to 10% for the year. I'll give you some more color on what we've been dealing with in terms of weather in a couple of slides down the road.

In the areas of the Western Rockies, Uintah, Piance, and Lake Creek, we will be spending limited capital in those areas in 2007 primarily because we've spent most of the money to develop the pilots on those projects in 2006. We'll be completing the final work on those projects this first quarter and then the process will be to evaluate the performance of those pilots as we get into 2007, into the second half of 2007 and the idea would be, determine which of these will be able to be evaluated for future commercialization.

Scott mentioned we do have several shale gas plays we're working on. Several of these are at a stage where we're spending money on them but they're too early to discuss in terms of results. You'll see us through time giving you more data as more information is known.

Turning to Canada, we have about a 50 well winter access development drilling campaign which is our typical number of wells in the northern areas of Canada, they are winter access only. In the southern area of Alberta, Horseshoe Canyon, we do have about 40 wells that need to be tied in from our 2006 program. We'll be evaluating what to do in terms of ramping up Horseshoe Canyon as we get into the second half of this year. As you may recall most of our drilling is done mid year there or in the second half of the year after we finish our winter campaign, and what we do in Horseshoe Canyon will be highly predicated upon what happens in terms of North American gas prices as we get into the year. In the case of Permian, again, we had an excellent 2006 and expect that to continue, where we have a 300 plus well program expected in 2007, and we think can generate similar growth rates, 15 to 20% as was approximately the range in 2006.

Scott mentioned our successes in Edwards. I've got more slides on these to give you more detail later. Suffice it to say we're very excited about what's happening in Edwards and look forward to its future in terms of its contribution to production growth. We do have a project also which we're progressing in Mississippi that we'll be drilling some more wells on in 2007.

Turning to slide 12 and this is now focused on West -- on Africa, first I'll talk about West Africa. We had previously announced a process, a sales process where we're going to try to sell or otherwise reduce our interest in these West Africa assets. As of now, we have really yet to reach an acceptable agreement to sell these assets and accordingly, we're going to be continuing to evaluate interest from several parties but the result of which is in our 2007 capital budget, we are including the amounts that are going to be needed to drill a couple of wells in West Africa. The first is expected to be spud during the second quarter this year, 2007, and the second would be expected to be spud in the third quarter. Both of these wells are in deepwater Nigeria. Incidentally, we've also terminated efforts to divest of our remaining Gulf of Mexico shelf assets. You recall we started a process last year to sell those assets. We simply received no acceptable offers and therefore, the assets will continue to be retained by Pioneer.

In the case of Tunisia, Scott already mentioned five successful wells drilled in the end of '06 and into early '07, and this is an area of course we're trying to move towards true core area potential for the Company and I've got another slide so I won't go into too much detail here, but suffice it to say we're evaluating future drilling both exploratory and appraisal based on our recent successes. And South Africa, pleased to say the South Coast Gas project is on schedule, on budget, with production expected the second half of 2007. I've got a detailed slide on that as well to come.

So first, discuss the Spraberry, that's slide 13. I think it's clear looking at the 2006 results as Spraberry has proven to be one of our key growth assets. We had an outstanding year in 2006 growing production 21%. We had ramped up drilling from the prior year of course in order to accomplish that and one of the benefits we've had is to be drilling the wells deeper to the Wolfcamp as well as the significant bolt-on acquisition campaign Scott mentioned. That is really adding more acreage for future drilling and many more locations. And toward that -- and we added about 230,000 gross acres that have substantial resource potential we show on the slide about 50 million BOE of Resource potential.

The drilling campaign will continue. We've got many years of inventory here. 3,000 locations is extremely conservative as to what we would have in the form of inventory but that in and of itself at today's run rate of drilling would be 8to 10 years of inventory. We have, we are running in the neighborhood of 14 to 16 rigs in the field. That will easily accomplish a 300 well program. About 85% of those wells will be drilled to the deeper Wolfcamp which adds some cost but also adds substantial reserves.

We have, as I mentioned in the last quarter call, now implemented and are now using our new pulling unit fleet. That is substantially reducing our operating cost in the field. We calculate about a 5 to 7 million per year savings using our own pulling units. Pulling units are one of the areas of expense that actually are continuing to increase, so we're very pleased to have accomplished that transaction. In terms of 2007, we are pegging Spraberry growth rates in the neighborhood of 15 to 20%. Really, this is proving to be a foundation growth asset for the Company. I think it will be for many years.

Going to slide 14, in Raton, I mentioned earlier how pleased we are to have had the excellent results we had in 2006 where production grew about 10% based on a 300 well campaign , and we'll drill a similar number of wells in 2007, somewhere between 250 to 300 wells with the 2 to 3 rigs we have in the field where we have well over still a thousand locations to drill. There, of course, we implement and have had in place for several years based on the old Evergreen model an integrated well services program that saves us substantial money as well. We calculate 35 to 40 million a year of savings owing to the utilization of our own integrated services group. We have been very successful adding wellhead compression in 2006 and that will continue. We'll add about 200 wellhead compression facilities in 2007, and about 400 pump off controllers all of which are adding to number one, production and also field efficiency. Overall, as I mentioned a minute ago, Raton, is expected to grow in the neighborhood of 7 to 10%. The low rate of the range again relating to the weather impacts which I'll talk a little bit more about in just a minute.

Okay, in terms of Edwards, Scott already alluded to much of our success in Edwards, but on slide 15, we continue to show progress in expanding our Edwards Trend area and this is of course in relation to and taking the technology and successes we had in Pawnee and extending those along the trend. We have now continued to add the acreage of about 270,000 gross acres, and as Scott alluded to, we drilled six new discoveries that last year through a focused exploration program, and that's about 90% success in terms of exploration, about twice as good as what we thought we would be dealing with when we entered into the expansion plan. And the six discoveries have added in the neighborhood of gross resource base of about 150 to 325 BCF.

As expected really we expected the fact that we would have essentially flat production in the field area, that is the combination of Pawnee and Edwards in 2006, and that's a combination of the fact that we were drilling the several exploration wells in 2006, in addition to which most of the exploration wells are vertical well bores which typically are relatively limited in terms of their production versus what we would do in terms of the subsequent drilling of development wells which are horizontal based and we'll make a multiple of the vertical well bore. So that definitely is going to limit what the production can be from these wells while we're only drilling vertical exploration wells. We'll drill about 35 wells in 2007 and, in addition to which what we're trying to do is complete the seismic program. I mentioned this in detail on the last call, but 3D seismic is very critical to make sure we can properly locate our horizontal drilling campaign for optimal production in these reef trends. So we've got 850 square miles of 3D to be shot. We've got three surveys already underway so that process is going well. It simply is is going to take several months before this can get done based on the fact we're limited, permitting takes time, the shooting takes time, land owner approvals take time, and we have limitations in hunting season. Suffice it to say, it will take a good part of this year to have all of that 3D shot.

While we're doing that, we're going to be directing most of the drilling to lower risk, horizontal development drilling in Pawnee and on our existing discoveries where we already have 3D. The whole premise here is 3D is needed to make sure we're accurately locating the horizontal development wells so we'll be drilling those wells in areas where we do have the 3D and holding off in those areas where we do not yet have it shot and processed. We will be doing some more work in an in fill drilling campaign in Pawnee. We've got some excellent results from a new horizontal well that was recently drilled within the existing Pawnee area of the field that made 5 million cubic feet a day so it surprised us to the positive so we're definitely looking at the potential for more in fill drilling within Pawnee.

In addition, we have begun to evaluate new frac techniques within the existing Pawnee field. Typically, as you may remember in my prior comments, the history has shown that we just used a light acid stimulation on the open hole section of the horizontal as the basic technique of stimulation. If you look through the history. We've just recently drilled or actually refraced a horizontal section with a sand propit and have substantially increased the production rate from that existing well. Now, then, we'll probably look at using some intermediate high strength propits in the future but the bottom line is if we can go back into the Pawnee field and reenter several existing horizontal well bores and make an impact like this first well has shown us, we could have an ability to substantially increase production from the field, so we'll be doing a lot of that work in 2007.

We also are working hard to increase the infrastructure in the area in order to accommodate the new production that we're going to be getting and also to maximize our existing plant assets in Pawnee. We're in the process of expanding an existing 8" pipeline and adding 37 miles to it to gather some production from our areas to the Northeast of Pawnee and bring that gas back to the Pawnee plant. The fact is, all these things take time and effort and we're right in the middle of it in 2007. And what we'll do is after we get through this period of shooting 3D and evaluating it, we'll be back drilling exploration prospects in the latter part of the year and have two to three already identified for drilling.

With all of this said, we think that if you compare 2006 to 2007, and the entire Edwards Trend area we'll be up year to year about 20 to 25% and we'll be adding substantially to resource potential as well. So as Scott mentioned, it and Tunisia in and of themselves are going to be adding substantially to our growth rates. The bottom line is we continue to be excited about Edwards and believe it does have substantial growth and reserve potential for Pioneer.

And going to Tunisia, slide 16, we've had a lot of success here in 2006 and early 2007 which does give us some confidence that we're heading more towards a core area asset which is something we've mentioned as a goal. In the atom area, we've had continued success in more development drilling campaign with over 90% success in the block and of course that's where our current net production comes in terms of oil from Tunisia, but in our three areas, including Adams, Jenein Nord where we operate and Borj El Khadra to the south, we have substantial resource potential that really has come out of having shot and interpreted a new 3D program last year. We think we have about 30 prospects identified. These will be exploratory of course with resource potential in some of these as large as 20 million barrels, so this could have potential high impact.

Recently, of the five wells that we determined have been successes, we've tested four of those at a combined gross rate of about 13,000 barrels of oil per day, so that's obviously very substantial. The last has not yet been tested but will be tested shortly. But this gives us some confidence, we are talking about high rate, high impact wells.

So when you look at 2007, what's the plan? Well, first of all, we need to tie in our production from our recent drilling in the case of Adam and BEK, these are areas that are close to existing infrastructure so that can be tied in pretty quickly in the first quarter. Jenein Nord we need to lay some pipe out to our discoveries there and some facilities so we don't expect any significant impact in terms of production until the second half of '07. We do have three new wells planned in '07 in our budget. One is an exploratory well in Jenein Nord and two, Adam wells as well. We anticipate if we continue to have the kind of success we have, we'll look at increasing our campaign to do additional exploration and appraisal after we evaluate the recent drilling campaign and we do have the rigs available too, one of which is a Pioneer operated rig in country. We will be able to increase gas sales in the country by the second half of the year, we hope, in relation to a gas pipeline expansion which is going to be under way in the second half. In addition to which we're evaluating the potential with some of the other producers in the country, laying new pipelines to new markets to move a substantial amount of gas resource that we have in the southern part of the country. Overall, Tunisia, we believe can grow 30%, 30% plus in fact, between 2007's annual annual number and 2006.

Slide 17 focusing on South Coast Gas. As I mentioned earlier, it continues to be on schedule and on budget. We're tying back several wells as you may recall to the existing FA platform. You can see actually us splashing some of the subsea infrastructure on the right photo. We have the all seas Lauralei pipe vessel out in the field as we speak ready to begin laying the pipeline umbilicals for this field operation so this is going extremely well. We continue to expect production second half of 2007, and this is an extremely strong project on the basis the gas here is tied to oil prices with very minimal operating costs as well. Still look at the reserve potential here on a gross basis of about 200 BCFE and there are expansion opportunities past the current contract which just goes through 2012. So when you factor in the expected decline of Sable and then the incremental production coming from South Coast Gas, we think South Africa grows in 2007 about 20 to 25% versus 2006.

Slide 18 is a discussion of Oooguruk. This is the biggest project on the North Slope in 2007. In 2006, of course, we completed the gravel drill site and that's shown in the photo to the left on the bottom. Out on that drill site today, we have about 300 people working with the capacity to move that to 485 people at its peak, so this is essentially like a little ant hill of activity as we're working towards the installation of our modules and equipment. The modules were constructed in New Iberia, Louisiana and Anchorage, about 50% of which are already on the slope. In fact you see the photo on the bottom right of one of the modules being shipped out of New Iberia last fall. The rig is a neighbors rig which is being retrofitted for this specific use and will be out on the island in April. Drilling to commence in the latter part of 2007. First production comfortably again, in 2008, and peak gross production will not occur until 2010. This will be a growing asset for us as the development drilling occurs over a two to three year period.

Substantial Resource base, 70 to 90 million barrels on a gross basis. We have not yet booked any reserves at Oooguruk. There are also some expansion opportunities. We have identified satellite fields that have been defined by earlier drilling that we could reach with extended reach wells from Oooguruk, so that's kind of in the pipeline in terms of future potential adding into the existing projects.

So in finalizing my comments I've got some photos here for you discussing weather and they are really on slides 19 and 20. Of course, in the month of January, there wasn't much weather in the Northeast or in the East in terms of snows and cold weather but I can tell you, in our production areas is where it all was when it was warm in those areas and you can see the impacts of the major winter storms that hit both in our western division activities and mid-continent. You can see substantial impact to, for example, knocking down power lines, knocking down phone lines and so on, with these massive ice and snowstorms and the only thing it was good on as you can see is sledding off the roof of your house with your dog. Other than that it's not very good for oil and gas operations.

Slide 20, this is actually the one I showed before was mid-continent operation. This is Raton. You can see a stuck Pioneer truck and you can see a couple of our employees working on a new problem and that is snow. On the top right you see Israel Cardenas who is an equipment operator on one of frac crews and our well services group in Raton and although he is an equipment operator, what he's using right now is a snow shovel. That's his current equipment while we're trying to get out of the snowstorm so it gives you an idea of what we're dealing with.

In the bottom left you see one of our other employees, Carol Leframboy who is a Regional HR Director in Trinidad walking out her back door. So we really had a lot of problems in January and accordingly if you combine the effects of both mid-continent and Raton, we have lost what we think is about 3,000 barrels a day on an average basis for the first quarter due to these weather issues. And with that I'll pass it to Rich for a discussion of the fourth quarter and also an outlook for early 2007.

Thanks, Tim. I'll spend a couple minutes on slides on reviewing the fourth quarter activity and results and then I'm going to switch and talk about first quarter guidance. As Scott mentioned, net income for the quarter was $28 million or $0.22 per diluted share. That did include three unusual items, the first two you can see on the slide there of which are related.

Just a little history on those items. Back in 2005, the Company's East Cameron 322 production facility was destroyed by Hurricane Rita. Prior to the fourth quarter of this year of 2006, rather, the Company had accrued an abandonment liability related to that facility of $86 million, but that assumed we would be able to wreath in place the debris associated with that platform destruction. During the fourth quarter, we were notified that our wreathing and place application was denied which now means that we're required to haul that debris to the onshore and cut it up and dispose of it. As a result, in the fourth quarter, the Company increased its estimated accrual by $33 million to bring our total accrual to $119 million.

As we've mentioned in previous quarters, the Company does maintain insurance for this type of event and as a result in the fourth quarter, we recognized into earnings $43 million associated with the expected future recovery of the debris removal portion of our claim. Rather than reporting the increase in our abandonment accrual in exploration abandonment expense in the income statement as we previously reported earlier in January and in the insurance recovery in other income, we have for ease and clarity net of the two items and added a new line to our income statement called hurricane activity net, which you'll see on the schedules that we attached to the press release that we sent out yesterday. I think it's also important to note that a substantial portion of the remaining estimated abandonment accrual is also covered by insurance and we expect to recognize those insurance proceeds in future earnings periods.

The other item impacting the quarter was a charge of $18 million associated with three previously drilled discoveries that we completed the technical work on during the fourth quarter and determined that we would not pursue further development of those projects. The end of the year, the Company continues to have a strong balance sheet as Scott mentioned with the net debt at $1.5 billion at the end of the year and net debt to book capitalization at 33% down from 48% at year-end 2005.

Turning to slide 22, for a review of our realized commodity prices, you can see that the Company's price realizations including the effects of hedging and deferred revenue amortization associated with our VPP's looking specifically at oil prices and excluding VPP deferred revenue, or realizations for the fourth quarter were down 15% compared to the third quarter principally due to the drop in NYMEX oil prices. Similarly, fourth quarter NGL prices were down 16% from the third quarter as product prices followed the decline in oil prices. Looking at gas prices, and excluding VPP deferred revenue, realized gas prices for the fourth quarter were down 12% as compared to the third quarter. The decrease is primarily attributable to certain gas hedges losing hedge effectiveness under FAS 133 during the quarter which results in the Company reclassing those -- that hedge activity to other income. Ignoring the FAS 133 impact, underlying realized prices have been essentially flat though since the first quarter of 2006, and you can see our realized prices that were received on the underlying gas production on slide 29 in our supplemental schedules that are attached.

Turning to slide 23, where we talk about production costs, total production costs for the fourth quarter were $10.52 per BOE, down 7% from the third quarter. The decrease is primarily due to lower than expected 2006 ad valorem taxes and reduced workover activity in the Spraberry and Raton fields in the U.S. and in less workover activity in Canada. The decrease was also, was partially offset by an increase in base LOE which is principally attributable to the Company receiving less third party gas processing fees as a result of the lower NGL prices which is how we are compensated for processing third party gas. Also included in the base LOE is some small incremental costs related to South Texas as we were adding new wells to production.

Turning to slide 24, to cover first quarter guidance. Daily production for the quarter is expected to to be 97,000 to 102,000 BOE's per day and as Tim mentioned down about 3,000 BOE's per day due to weather issues and so without that impact, we would have provided guidance probably in the 100 to 105,000 BOE's per day range for the first quarter. Production costs for the first quarter are expected to range between $11.25 and $12.25 per BOE. Higher than what we had the last couple of quarters by about $0.25, primarily due to the loss of production during the quarter and incremental costs to repair and get back online our production that we lost in January.

Exploration abandonments for the quarter are expected to range between 50 and 90 million. A couple items in there that Tim mentioned, we've got the two wells that are being spud in the first quarter in Alaska's NPRA area and our exposure there is about $25 million. We do have a number of wells going down the Edwards Trend, Canada and Tunisia in our resource plays and so there you can see the exposure is about 30 and the other significant item that Tim mentioned was in our Edwards trend. We do have a significant amount of seismic being shot and so you can see that we've estimated about $15 million for that seismic shoots in the first quarter. DD&A is expected to be 10 to $11 similar to the fourth quarter actual number. G&A is expected to be between 30 and $35 million for the quarter and does include performance related compensation that is typically paid in the first quarter. Interest expense is expected to be 25 to $28 million for the quarter, cash taxes 5 to $15 million, principally related to Tunisia where we are a cash tax payer bringing our overall effective tax rate for the Company for the first quarter between 37% and 45%.

Turning to slide 25, we do have a list of supplemental information that we've included in the back of our PowerPoint presentation. I would encourage you to take a look. I think it's some good information about the Company and to help with your modeling and so at this point I think that ends my comments and we'll open up the call for questions.

Thank you. [OPERATOR INSTRUCTIONS] Our first question comes from Robert Morris with Banc of America.

Good morning, gentlemen.

Hi, Bob.

Just a few quick questions. The 10% plus production growth target, that's absolute and not per share?

That's right.

Okay. Second, on the acquisitions, those came at a pretty low finding cost. I know there are future development costs associated with those but appear to be less than $5 per BOE. Can you just give us a little color as to how you picked up those so cheaply?

Yes, primarily a lot of them are in the Spraberry trend area where we operate over half the wells in the field. We're such a dominant force in the Spraberry that we've been able to drive out competition and so when you combine the lease cost like in the Spraberry trend area with the capital cost to drill the well, your all in finding cost is about $11 per BOE, Bob.

That still seems, well I guess that's pretty cheap.

It's not -- it's not as -- when you dominate a play like that, you're able to -- you just don't have the competition and the infrastructure and stuff like that, and so it's not like paying 10,000 an acre in the Barnett Shale.

Right. They really don't have anybody else to sell it to. On the budget here, you mentioned using strip prices is going to be about 200 million above your cash flow, and just curious as to how much, if commodity prices did come down or the strip didn't hold up, how much you would be willing to borrow to hit that budget? And then also, for the $300 million share buyback program, how much you would on top of that prior to carry out what you would do there this year?

Yes. If we see after March 31, the gas storage is still high and gas prices fall back to where they were, let's say just a few weeks ago, there are some areas that we control that we would reduce capital. That could be Raton, for instance, where we control our own destiny there, we own our own rigs. It could be some other areas, we could postpone some seismic, so we do have the flexibility to reduce capital, and obviously, as stock price drops, becomes volatile, the more it drops, we're always going to put and if we can buy shares, 35, 36, $37 a share, we'll definitely be buying the shares so with a strong balance sheet and debt to book of 33% and we don't see a problem of managing through that type of cycle. 2008, 2009 obviously we show a significant pick up in cash flow with the growth, in addition to the fact that a lot of our under water oil hedges are coming off and VPP volumes are coming off. So cash flow per share just to remind people is growing at 15% compounded where production is only growing about 10.

Yes. So combined for spending and share buybacks, the limit on how much you would borrow would be what? 300, 400, 500 million?

Yes, debt to book needs to be 40% or less, so it's really a function of how we feel about our projects and we're growing, so we're just going to manage it through the cycle. Now our $300 million program, the goal is to buy it opportunistically and we're not going to rush out there and spend the whole amount in the next month or two months, so we're going to buy when prices are low, so with a strong balance sheet, we feel confident in managing that cycle.

And then just last question real quick. The 750 million BOE resource potential, you would expect to recognize that over what time period? Three years, five years?

Over the next five years.

Okay, great. Thank you.

Your next question comes from David Tameron with Wachovia Securities.

Hi, guys, good morning.

Hi, David.

A couple quick questions. Can you talk, you guys kind of, I know for brevity sake you skipped over some of the details of your Rockies pilots, can you talk a little bit about what you're doing in Sand Wash, Lake Creek, recent results there, anything you can share with us?

Yes, basically all we're doing is production is increasing in all three pilots and we probably need another six to nine months as we bring on production to make a decision on all three projects, so obviously, we have not booked any reserves and we'll be making a decision in the next six to nine months on those projects. So there's really nothing new to report. We'll report a lot more detail at our analyst meeting in June.

Okay.

On those three projects.

Okay and then on the Raton, I think you said two to three rigs is kind of what the material is running in '07. You guys, correct me if I'm wrong, but Evergreen had closer to -- the old Evergreen, five or six rigs in that fleet. Did you lay down some rigs or are they doing something else or what's, is there a discrepancy there?

No, Evergreen basically ran the same name, same number, two to three rigs per year also, very similar to what we're doing. In fact they were drilling less wells with two to three rigs.

Okay, so they're drilling -- I thought they were drilling the same amount of wells with more -- you're saying less wells with the same rigs?

Yes, they were drilling 150, 200 wells a year with two to three rigs.

Okay, and then last question, on the Raton, I mean, there's -- whether it's come from your side or from our side, there's been talk about potential for an MLP in the Raton of those assets. Do you care to comment at all?

No. As we stated a year ago, we saw the first MLP come out. They stumbled. They had a lot of accounting problems. They recovered from that. There's been six more MLP's come out, and they are all trading with assets probably not as high quality as we have and they are trading at huge multiples, so obviously we're continuing to monitor those very seriously and continue to discuss whether or not Pioneer should be doing that, so obviously we wanted to watch liquidity in the market, wanted to see what happens with the MLP's and how they trade, and so far, obviously, if you look at the marketplace, it's been very positive, so something we're seriously continuing to look at.

Okay and what assets in your opinion, Scott, fit into an EMP, MLP portfolio?

Well, it's really, any long life asset fits into that, so it's not necessarily Raton. All of our assets are long life, excluding what's going on in Africa, so all of our assets in some form or fashion potentially are MLP candidates.

Okay good and just to clarify, I think Bob asked this question but just to clarify. The 10 -- the 10 to 12% long term, 10% for '07 is absolute and the 10 to 12% long term, is that per share?

Per share? No. It's production growth.

Yes, yes, I'm sorry.

As we buyback per share, it's will improve from that.

Okay, so the 10 to 12% is absolute production growth level, not a per share level?

That's right.

Okay, thanks.

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

Good morning.

Good morning.

Hello, Robert.

Scott, I guess I was expecting a South Coast Gas and Oooguruk to be booked at year-end '06. Could you have booked these fields then and if so why did you choose not to?

We have booked some South Coast Gas, probably about 2/3 of what we could book. It's always best to be conservative and watch production history. Oooguruk, we have no production history, so we wanted to continue to watch that too, so we just want to be conservative and it's better to have performance before you start booking. Oooguruk, we're actually injecting water and under strict SEC guidelines, this is very similar to Alpine. It's a little bit -- the geologic formation is similar to Alpine. It's a little bit different quality of crude, and so as we inject water into a secondary expansion in Oooguruk, we will be booking reserves with that success of that water flow.

I see. That's helpful, and--.

That 50 million barrels we booked primarily from -- 50 to 60 from '07 through about '09.

Okay. At Oooguruk?

At both of them.

All right, and then at South Coast Gas, can you tell me what you're estimating peak production will be and do you hit that immediately or does that come kind of later on?

Yes. There's a, well, one thing interesting is that there's a key project and we have a well in Sable that we're reinjecting 90 million a day and because of high oil prices, Sable has been extended into late '08, early '09, and so we actually hit peak production in this well from Sable comes on, and that will probably be late '08 to early '09. So it ramps up until early '09.

Can you give me a rate?

We gave the rate, you can sort of back in the rate from '06 to '07.

Okay.

I think our rate, our peak rate is about 45 million a day.

I can get with him.

Yes. Frank will get with--.

This is Frank. I'll get with you and show you how to ramp it up.

Appreciate it. And I apologize if you guys have said this already, but can you -- have you mentioned what the contracted gas price is there?

Yes, we have. It's been in several slides. It's10 -- take [Brent] price divided by 10 and we have the -- Tim mentioned that the operating costs are very low. They are almost insignificant and the reason is we negotiated the processing charge inside the gas price, so take your Brent price and divide by 10 so we should roughly get close to about $6 based on current Brent pricing.

Okay and just moving on to Pawnee, seeing encouraging results from refracing existing wells with sand profits. How many locations do you have here to refrac and can you tell me what the average cost is for one of these jobs? Is this a multi-stage frac?

Well, let's see. I think we have 35 existing horizontal wells to 40 horizontal wells in the field. We could theoretically reenter. We're certainly not at a point where we would say we've got all of those on the horizon but definitely they are potential for the future.

They are all open hole. There's no liners, slotted liners like you see in some of these shale plays.

What is the average cost for one of these jobs?

About $300,000.

Thanks so much, gentlemen. Appreciate it.

Our next question comes from Sven Del Pozzo with John S. Herold.

Good morning.

How are you doing?

Good, how are you?

Fine.

Yes, I'm wondering, is that a -- that 13,000 BOE per day gross well in Tunisia, is that one well?

No, it's four wells. We said we had four discoveries, I mean, four wells that came on out of five, and so that's a combination rates of four wells and our interest ranges from 20 to 50% in those four wells.

Okay, and could you -- what kind of income tax rate and royalty are we talking about in Tunisia?

I think Frank can call you back on that but our royalty rate is about 15%. Income tax rate varies but Frank can give you a call back on that.

Okay, and then regarding the Edwards trend I was wondering with, I know you haven't probably not enough drilling history yet, but on those eight or so wells that are producing, what has been the variability in the IP rates that you've encountered?

The important thing is we the -- we just now started drilling horizontal wells and our last four wells have come on about 3 to 3.5 million a day each, horizontal appraisal wells, so the horizontal wells tend to produce at that rate a lot longer versus a vertical well. But vertical well may come on 2, 2.5 million a day and fall off quicker where horizontal well is exposing about 2000 feet or more pay, because it's horizontal and so we're starting to see, that's why we're getting more aggressive on our growth rates based on just recently seeing some horizontal appraisal wells for the first time.

Okay and that page nine slide that you've got that tells you the different measures of profitability by region, is that Edwards trend -- is that a vertical development or a horizontal?

That's a horizontal.

Okay and yes, I guess will you be able to get more rigs for Tunisia?

We have three rigs right now, so one that Pioneer operates and two -- and it's a question of as we see production success, how far do we keep drilling during the year? As Tim mentioned, those three rigs are drilling three wells right now and we got to decide what to do after these three wells are drilled.

All right thank you very much.

Thanks. Any last questions?

We have one from Gil Yang with Citigroup.

Yes, Gil?

Hi, good morning. Can you just, maybe Tim, just comment on the weather problems, if they are fully resolved or are there some lingering issues?

Well, in general the weather has been a lot better, but we have a lot of problems that need to be rectified that have been caused by that weather that take really weeks to fix, whether that's electrical problems or other issues in the field. So we are clearly making progress on it. We still are not back to what we call full production in Raton as we speak. Mid-continent operations we essentially are back at full production but we really got hurt badly in January is the point and the numbers we're giving you are really reflective of a bad January more than it is any outlook for February or March.

Is there any chance that it actually gets worse in the sense that it takes longer to get back online and that 3,000 goes up to 4,000?

I doubt it. I mean, you got to tell me what's going to happen in February from now on and March weather.

I just more meant that if you don't get the repairs done as quickly, can that 3,000 go up a little bit?

No. That's already factoring in what the we think it will take in terms of maintenance work for repair.

Okay. In the -- in booking Spraberry, I think that you mentioned that you book locations or could you comment on how many locations you tend to book in Spraberry?

Yes, we take all farm outs, leases, joint ventures as we enter into them and book them in the acquisition category, so almost all of those acquisitions is not producing property acquisitions. They are leases, farm outs, joint ventures. Two with major oil companies, university lands we had a large lease sale there, in addition, acquiring open acreage as we continue our development drilling program.

All right, okay. And then last question is in Raton, the returns that you give for those wells, does that include the retrofitting cost of the compressions that you've been doing?

Yes. It includes all hook ups.

And state-of-the-art gathering, et cetera?

Right. It includes all gathering cost.

All right thanks.

We have time for one last question.

Last question will come from Marshall Carver with Pickering Energy.

A couple of quick questions. What sort of royalties do you have to give up on those acquisitions? It looked like they were such low cost. Just wondering if that had a -- what sort of royalties were attributed to that?

Yes, they range from as high as 25% royalty to as low as probably 3/16ths. That's a general range.

Right. And in the op cost at Spraberry you talked about the pulling units decreasing op cost. Could you give us some numbers there what the operating costs were before and where they should be going?

Well, I think Tim's number will translate. What we want to see is a $0.50 per BOE reduction, but that's combined with all of our new productions coming on, the average operating cost is about 4 to $5 per BOE. So when you look at Spraberry since we did the VPP on Spraberry it's $2 higher because of the VPP, and -- but all of our new production obviously is not under the VPP, and also, all production, those units represent what, about half, about half of our total pull units, so if we had bought another 14 units, we see reductions of about $1 per BOE, but right now it's estimated -- that 5 to 7 million Tim mentioned is about $0.50.

Okay and one last question. On the Gulf of Mexico shelf sale, could you remind us the production there and was that previously excluded from 2007 guidance and now it's included?

It's always been -- until we sell something, we keep everything in our guidance, so it's about 2000 barrels a day and it's on a slight decline.

Okay.

The bids came in in fourth quarter, obviously crude prices were falling and the bids were not acceptable at that point in time.

Okay, thank you.

Okay. Frank, you want to close?

Yes. Thank you very much for joining us this quarter. Please, if you have follow-up questions, call myself or Scott Rice. The number is on our press release and most of you know how to get us anyway. So, have a good day and again, thanks for joining the call.

That does conclude today's conference. We thank you for your participation and have a great day.