先鋒自然資源 (PXD) 2007 Q1 法說會逐字稿

Good day, everyone and welcome to Pioneer Natural Resources first quarter conference call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer, Tim Dove, President and Chief Operating Officer, Rich Dealy, 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.px.com. Again, the internet site to access the slides related to today's call is www.pxd.com. At the web site, select investor, then select investor presentations. The company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in the last paragraph of Pioneer's news release on page 2 of the slide presentation and in the most recent public filings on Forms 10-Q or 10K, 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 thank you for joining us. Let me briefly review the agenda for today's call. Scott will be the first speaker.

He's going to highlight several strategic initiatives currently being progressed by the company and the expected results from these. After Scott concludes his remarks, Tim is going to provide an operational update. And then Rich will cover the financial highlights from the first quarter and provide earnings guidance for the second quarter. He will also comment on production growth and capital spending over the remainer of 2007. After that, we will open up the call for your questions.

Before turning the call over to Scott, please let me remind you that last week, April 23rd, Pioneer announced that we plan to form two master limited partnerships for the purpose of owning interest in long line oil and gas assets. We anticipate that the MLP will be formed to initially acquire an interest in a portion of our approved developed fields in the Spraberry field in west Texas, the second MLP is expected to initially acquire an interest in a portion of our crude develop reserves in the Raton Basin.

Aproximately $250 million of the partnership units are initially planned to be publicly offered and each of these MLPs subject to market conditions. Following the initial public offerings, Pioneer will be the general partner of each of the MLPs and hold a majority ownership in the units of each of the MLPs. Pioneer will continue and own a partial working interest in the assets that will form the MLP's. The rules of the Security and Exchange Commission limit the stature of the information that we can provide about each MLP until the time that we file a registration statement for the initial public offerings of the units in that M.LP.

This will impact what we can say about the MLPs in this presentation during today's Q&A session, and in follow-up meetings. We anticipate that the registration statement for the first IPO will be filed during the third quarter of 2007, with the registration statement for the second IPO to follow during 2008, subject to market conditions. We appreciate your patience during this prefiling period and look forward to speaking to you much more down the road as the rules permit. As a result of these disclosure restrictions, we are postponing our analyst meeting which was scheduled for June 6th and 7th. You may have received an announcement about that yesterday. You will be notified when a new date is set. With that, I will turn the call over to Scott.

Good morning. We're going to start out on strtegic highlights on Page 2. First comment - We are expanning our drilling program, primary due to drilling success in Tunisia, (inaudible) and Spraberry. Tim will give you more detailed information, but I think one of the key ingredients is the fact that we are now declaring Tunisia a core area, with our four most recent tests testing 27,000 barrels of oil per day with three of those wells where we own 100% and obviously the government will come back in for 50%.

We have announced increasing our share repurchase program from 300 to 750 milllion.. We also, due to the success in Tunisia, the horizontal development Drilling going on in Edwards offsetting our discoveies from 2006 and in the Spraberry Wolfcamp (inaudible), we are increasing our annual production per share growth from 10% to 12% on a compounded annual growth rate from 2007 to 2010.

In addition, we expect our cash flow in the current market pricing environment to double between 2007 and 2010. And that's a combination between the growth and the production of the exploration of some oil hedges we put on about four years ago and declined tin (inaudible) obligations.

In addition, as we announced a few weeks ago, we are planning to form two MLPs, Spraberry and Raton to enhance this current low-risk strategy. Turning to Slide Number Three, in regard to CapEx, we are expanding our 2007 drilling program by about 200 million.

We are going from 1.1 billion, to 1.3 billion. All of it is due to the drilling drilling success in Tunisia and Avards. and also due to the successful wells we're making in our Wofberry Play adding the Wolfcamp to the Spray berrry we'lre seeing great results there..

Also due to the presence of $70 crude and also we are beginning to layer on several hedges at $70 to $71 a barrel in 2008 and 2009. I think one of the key ingredients you see, our development projects in our high impact exploration represent about 26% of our total capital budget.

That will be declining to about less than 10% going into 2008 and 2009. And you will see increases in resource plays and also in the development drilling as we complete both South African gas project, and Oooguruk project. and reduced high impact exploration to a very, very small amout.

Going to Slide Number 4, as we had mentioned already, we are increasing our share repurchase program from 300 to $750 million. We have bought back 31 million shares over the last two and a half years which represents about 21% of our shares outstanding.

We feel like it's important to continue to reduce shares over time. Slide Number Five, increasing our production for share growth target.

As you can see, It's primarily due to success in Tunisia and Everetts which are resource plays and also to higher growth targets coming out of the Spraberry, due to the fact that we are taking most of our wells to the wolf camp and seeing great results in hat play. So we feel very confident that we can deliver on 12% per share compounded annual growth rate.

Slide NumberSsix, just reemphasizes how we get, how does Pioneer double the cash flow, the free cash flow over the next four years from 2007, estimated probably closer to $900 million this year, based on the current price set. We do have some old hedges that are rolling off in 2007, 2008 that were done at very low oil price.

Our VTP operations are coming back to us and then with production growth, another $400 to $500 million, gets to us the 1.6, $1.8 billion cash flow. An important message that will be precash flow neutral in 2008, out CapEx will be equal to our cash flow, in our current pricing environment.

And secondly, we'll have excessive cash flow in 2009, 2010. Going to Slide Number Seven, again, we are limited in what we can say about the MLPs. We have really three key points -- Four Points here in regard to Slide Number Seven. Obviously the first reason to increase the valuation of Pioneer's long- life crude reserves due to the valuation difference between MLPs and Pioneer.

Secondly, to allow us to more effectively pursue acquisitions, having a lower cost to capital entity, which will be able to buy developed reserves while Pioneer would buy undeveloped reserves. And through this, you will see Pioneer get more aggressive on acquisitions in our core areas.

And over time, you will see us increase our rig count in all of our key areas, as we are successful -- if we are successful in pursuing these acquisitions. And then thirdly, obviously, a good pioneering opportunity to sell the crude reserves to the MLP's and apply the proceeds from initial offerings to potential future offerings to fund low-risk opportunities, share repurchase while maintaining strong financial flexibility.

We do state that about 90% of our reserves are long life and are eventual current or eventual MLP candidates. Let me now turn it over to Tim Dove to go over our current operations.

Thanks, Scott and good morning, everyone. In the first couple of slides, I'm going to give an overview of all of our current activities, but you will see that really my main objective today is to provide some more granularity on the three areas of our expanded drilling campaign, those being Tunisia, Edwards and Spraberry, as Scott has eluded to.

And, there are several sites we'll cover on those three. First turning to Slide 8, reviewing our North American activities for 2007, very pleased to say the group project, had a very good and productive winter season, the project remaing on schedule for first production in 2008, early 2008. The pipe line has essentially been completed.

The rig is on the island and being installed and we expect to begin drilling late this year. So, very good outcome when it comes to the scheduling related to the Alaska projects. We also have arranged for a rig to begin the process of mobing to Alaska to test another additional zone in the Cosmopolitan discover,y we expect that testing to be done in the second half of this year.

We expect to being drilling that well at at the time of the drilling 100% basis Pioneer. We also drilled two noncommercial wells this year in the NPRA area of Alaska. We're closely watching the results from wells drilled by a combination of Talisban and Petrocam in the same area that is relatively close to the Pioneer acreage. Rockies, of course we got a bit of slow start when the weather impacts hit us in the early part of the first quarter, but we are back, ramped-up production back to the curve we expected in the early part of this year.

We are maintaining a 250 to 300 well program that will deliver 7 to 10% growth, similar to what we experienced last year. So, everything is back up and running when it comes to the Raton production. We continue to evaluate several Shell gas plays in and around our existing core areas. It's early days and we will have more details to discuss with you over the next couple of quarters.

In Mississippi, we have drilled one of the two wells. The other well is now drilling and as soon as those are done, we will be giving some information as to what we can expect, but we are progressing in the infrastructure development, so as to be able to produce those wells in the mid-part of 2007. Turning to the right part of the slide then in Canada, we do have a substantial growth in production in the first quarter, compared to last year's first quarter, owing to our last year's drilling campaign in Horseshoe Canyon.

As you will recall in early April we did announce a new gas field discovery in northern Alberta that we put on production at about 18 million cubic feet a day. Most recently we did shut this field in, as we are waiting for the water disposal approvals.

Water production being slightly higher than what we expected and we're going to have to wait to get this disposal permit before we can put these wells back on production. We expect a permit at the end of the quarter. In the interim, we are installing tubing in the wells in order to enhance their ability to move the water.

And in doing so, the installation of the tubing will also lead to a slight decrease in what these wells can make when they are restarted. We have successfully added acreage in the area and we are slightly under 4,000 net acres in the new play. Permion and Edwards are the next couple of boxes.

Of course, there's a lot more discuss and I will go to those in just a moment. But suffice it to say, we are ramping up the Strayberry development campaign and Edwards we are seeing a deal of success both with respect to development of the existing discoveries and reentering of old wells.

Now, turning to Side 9, this is where we are going to talk for several slides about Tunisia later on, but beginning with the African activities. You have to start with Tunisia as a new core area. We have several more slides to discuss it, but having a great of success in this year's drilling campain, as Scott mentioned, with four wells testing 27,000 barrels of oil per day.

A Southcoast gas project is doing well, the FAA platform modifications are essentially complete,, the pipeline trenching is essentially complete and all the well hookups are essentially complete. So that we are confident that we will be able to meet the target of first production expected here in the second half of 2007. We do have two wells still to drill in West Africa to complete our commitments there.

The first will actually be spud probably later on this week, it's in Block 256, Offshore Deepwater Nigeria the drilling of these two wells will essentiall complete the higher impact exploration program in 2007 for the company. Now, the more granular slides, Slide 10 is a discussion -- a beginning discussion on Tunisia.

We are obviously excited to finally declare Tunisia as a new core area. It's a credit to the foresight and the skill of the technical staff which made this happen, related to all the Tunisian projects. Great deal of drilling success. A lot of it is coming from the identification of prospecttivity out of 3D seismic program shot in 2006. And we've had a great deal of drilling success as I mentioned earlier and as did Scott.

We tested very high rates on a significant number of positive wells. Accordingly, we're going to be raising our capital budget in Tunisia by $70 million, and that will have us drilling probably about eight more wells in 2007, and developing the discoveries on our Jenine Nord operated block where we had the three big wells.

So, what we are doing right now is we are submitting a plan of development for that block, probably the latter part of the second quarter and we are in the planning stages of laying a new 8-inch, three kilometer pipeline out to Jenine Nord and establishing plans for putting in place processing facilities.

So, this is going to be a very big positive, obviously with the needs to get this infrasscruture in place we don't expect really any production impact until the fourth quarter but we are very excited about the results to date. And accordingly, we ought to be able to grow Tunisia at rates even higher than we what we had earlier thought. We're now estimating that 2007 production could be in the neighborhood of 80% higher than 2006 and similarly, about 90% higher in 2008. So very big impact to the overall company production profile, owing to success in Tunisia, and this doesn't even speak to the potential in the near term and for that matter the longer term for potential gas sales. We have thrown a slide in here, Slide 11, showing a typical Tunisia well. IP'ing at about 300,000 barrels a day, there is a relatively long life wells. We actually have wells that are put on production even higher than 3,000 barrels per day. We consider this kind of the average well in the (inaudible). And importantly, each of these wells will make 4 to 5 million barrels of oil, and it -- the drilling -- the completion cost of these wells is $9 to $10. So very strong F & D, very strong returns. Tunisia has the best returns in the company on all metrics. Turning to Slide 12, I did mention that our success is to a great extent dependent upon new 3D seismic and the prospecttivity that's been generated from that seismic. This just gives you a sort of cartoonish thought there and that is, with 2d seismic in the area, especially with the difficulties that are presented by the topography and the overburden, we really do need 3D. You can see in one case in Jenine Nord that is shown on the top, on 2d seismic, our ability to image prospects is limited. We had one area, one specific prospect that increased in size by a factor of 10 by applicaotin of 3D seismic, and maybe even more importantly, we are identifying areas not to drill because 3D interpretation basically denigrates prospects and therefore we're not spending our money on bad prospects. Therein lies the key to high success rate, which we had over 90% success in drilling in Tunisia. And accordingly, we're developed about 30 plus prospects and leads on our 3 Key Blocks based on the applicatoin of new 3D seismic. And we will be shooting more 3D looking into the future. Page 13 is an important one, because it shows some detail on Jenine Nord, this is our 100% operating block just west of Adams. Jenine Nord is outlined in the yellow, west of Adam, and you can see the Adam area to the East showing the green producing field. You can see a couple of things on this chart that are important. First of all, you can see the shaded area of 3D as the green shaded area, where we have been drilling up the prospects that I mentioned earlier that have been generated from the interpretation of that 3D and we have three new discoveries on the block as shown in the black triangles and about four to five wells still o drill the remaining part of this year and that's where the additional capital will be going with about 20 plus prospects on this block identified for future drilling. So we are very encouraged about the future of Tunisia and specifically the future of this block. Now then, on page 14, Slide 14, we will talk about the second area that we will give you more granularity on. That's how the Edwards Trend expansion is going. We clearly have a lot of activity going and we are continuing to see very positive results. But that's both in the drilling of new horizontal wells and the refracts of existing wells where we've had a great deal of success. And accordingly, this is the second area we will be increasing capital. We will be adding about 60 million in capital, increasing our rig count and increasing our well count , increasing the rig count to 7 and our well count to 45 wells and we have another slide to show you infrastructure that we are building in the area to prepare for the increases in production. 3D seismic, obviously is critical out here as we discussed in several calls in the past. We are out, as we speak, shooting 900 square miles of 3D surveys on some of our recent discoveries with the idea of them being able to more properly locate the future development drilling horizontal wells. We have had a great deal of success in our lower risk development drilling. We have been doing while we have been shooting the 3D. In fact, we've five recent wells that each tested rates at over 4 million a day. I mentioned the fact that we are doing a much of refracts of our existing horizontal wells in Pawnee to increase the production and the reserves. We have seen multiples, significant multiple increases in terms of production using isolation packer devices to refract both vertical and horizontal sections. In fact we have seen rates on three wells increasing by factors of four and eleven times which obviously is an extremely fast payoff economics. Current production, up to about 45 million a day. We now have pretty good visibility on a rate of production increase this year compared to last, of about a 25 to 30% growth rate and similar for 2008. On Slide 15, a little bit more detail on what it's going to take to accelerate the program. We expect to have all of this 3D shot on the -- the shoots I mentioned earlier, as well as on some new prospects in the early part of 2008. And it will allow us to more effectively locate and drill the horizontal wells successfully that will be the key to the development. We have the one extra rig coming this year and one additional next year and that will allow us to move from this 45 well per rate, we are looking at in '07 up to about 60 in 2008. Important to this slide is just simply showing you he scheduling of events, the 3D being shot in certain areas and the rigs coming into the forefront for drilling to accelerate the program. Next couple of slides, 16 and 17 show just a little bit more detail on where the activity is. In fact, in Slide 16, we are showing where wells will be drilled. This actually shows you in detail where all 45 wells will be drilled. The vast majority this year, of course, are going to be oriented towards development drilling, where we are -- where we are shooting the 3D. We would rather orient the drilling towards areas where we have existing 3D or low-risk opportunities. We will still be drilling two to three new prospects along the trends as well. Needless to say this is an active campaign in a lot of different areas and it gives you some details there in terms of where the activities will be performed. Similarly, onSslide 17, we mentioned the fact that a lot of the areas that we are talking about are relatively limited in infrastructure. We have to build pipeline and (inaudible) treatment facilities out to some of these new discoveries and in fact we have current plans in place to double our treating capacity and we are extending one of our existing pipelines, a 44 mile existing pipeline called the 844 pipeline, another 37-miles to the north and east in order to gather additional gas from discoveries in that area and bring that gas back to the Pawnee gas plant. But the combination of existing capacity at Pawnee and the newly unstalled (inaudible) treatment should double our ability to treat gas and produce gas out of the Edwards area. And then finally on Slide 18, just a little bit of detail on what we can expect or we are experiencing. There are three wells shown here of horizontal existing wells in the Pawnee area. You can see the pre-stimulation rates typically 100-300 MCF per day increasing by multiples of four to ten or 11. As a result of $750,000 refracts. Very strong economics and we think there are lots of opportunities to apply this technology, both on existing wells and on new wells. So in summary, our Edwards Trend results continue to be very encouraging and this is both with regard to existing production enhancing as well as the development of our recent discoveries. And finally, a discussion regarding Spraberry.

Of course, this is one of our key resource assets. It has roughly 50% of the company's approved reserves. It has many years of drilling left.

And it's 25% of the company's production. We are going to be increasing the rig count out at Spraberry to take advantage of our strong margins and economics. In fact, we will be moving to about 18 rigs by mid-year. And moving the well count up to 350 wells.

And we are preparing for an even more aggressive campaign in 2008, up to 450 wells. As Scott mentioned, we are very actively working on bolt-on acquisition opportunities, as well as adding new acreage in and around this existing field. Our production, we think we can grow similarry as we did last year, about 18 to 23% in '07 and that same range, 20 to 25 in 2008.

And, we are, as Scott eluded to, adding a new moniker to our Spraberry business, and that is the Wolfberry. On Slide 20 we show that we have significant benefit from adding our -- or continuing to drill a little bit deeper into the wolf camp section and adding typically 20,000 BOE per well and doing so at strong attractive economics. Really what we are doing is simply combining the Wolfcamp with the Spraberry zones and enhancing the well performance well results and economics.

So in summary, I hope this granularity helps with you some understanding of what we are doing in these areas where we are increasing capital, but we are very pleased with our organic growth prospects coming out of Tunisia, Edwards and Spraberry. Rich, I will turn it over to you for a review of the first quarter and second

Thank you, Tim. Jumping into the quarter results, net income for the quarter was $30 million or $0.24 per diluted share, it did include two unusual items, both of which were related to the East Cameron 322 facilitly which was destroyed by Hurricane Rita back in 2005. The first was a charge of $19 million associated with higher than expected weather down time in the first quarter as we were out there trying to work on the abandonment process.

In addition, we also had -- when we got the subc operation, the downtime, and we recognized that we were going to have more work to do out there. And so we did increase our accrual by $19 million or (inaudible) on an after-tax basis for the first quarter.

Offsetting that was an insurance recovery of $5 million during the quarter that was related to debris removal. On an after tax basis, that came in at 3, so on a net impact for the quarter, the quarter t was impacted negatively for $0.07 for those two items.

I think just as a little bit of history, over the last five quarters we have increased our abandonment accrual, related to East Cameron, about $134 million, of which we received $5 million in cash from insurance recoveries. We do expect a substantialportion of that remaining balance will be covered by insurance and expect to get that cash in over future quarters.

We have recognized $43 million as a receivable related to insurance, and so the difference between the 134 and the 43 will come in as positives to future earnings in future quarters as well. Looking at first quarter results on the box on the slide there, you can see that we did put out first quarter guidance, and if you look at actuals, at hosw they came in, they came in as we expected and we put out the guidance and all of those items are within the guidance range or better.

So covering more of those on detail on the following slides, turning to Slide 22, where we show our production for the first quarter, we reported 98,000 BOEs of production, up 3% from the first quarter of '06. However, the first quarter was impacted negatively as we talked about in our fourth quarter earnings call by weather down time that we experienced in the Raton area, midcontinent area and the Spraberry area.

We estimate that that impact was about 3500 BOEs per day of lost production for the quarter. In addition, we had some deferred production that's going to get deferred to the second quarter, related to South Africa. Just due to the timing of oil listings there.

We produced slightly over 3300 barrels a day in South Africa but our sales reported due to listings was only about 2300 barrels per day, so that production will be deferred to the second quarter. So if we adjust our production for those two items, we would have been slightly over 102,000 BOEs per day for the first quarter and as you can see, that would have been higher than the fourth quarter production rate of 101.

Turning to Slide 23 for discussion of our realized commodity prices. You can see each of these bars did include the effect of our hedging portfolio and our BPP deferred revenue. If you look at oil prices specifically, you can see that we realized prices of $54 for oil in the first quarter, down from, you know, slightly under $62 from the fourth quarter.

If you strip out the hedging impact and the BPPs, you know NYMEX and realized prices were essentially flat for the quarter. The big impact of the quarter was really the legacy hedges that Scott mentioned earlier, negatively impacting our price realizations on the quarter.

NGL prices were down $0.50 but just really followed the commodity prices for the quarter versus fourth quarter. Looking at gas prices for the first quarter, and excluding the BPP deferred revenue. Gas prices increased 32% compared to the fourth quarter.

This is primarily attributable to the (inaudible) gas pricing rising compared to the fourth quarter and our realized prices, excluding hedging and BPP's for the first quarter were $6.28 per MCF versus $5.68 per MCF in the fourth quarter.. The other thing that positively impacted the quarter was the company's hedge position, added $0.44 per MCF to our price utilization, versus the fourth quarter which had a $0.59 per MCF loss to the quarter.

Turning to Slide 24, we cover production costs. Production costs for the first quarter were $11.86 per BOE, up 13% from the fourth quarter. This is primarily attributable to loss volumes that we mentioned, related to weather down time that we had in the first quarter and the associated repairs that we had to incur costs to get that production back online.

Secondly we also have higher workovers compared to the fourth quarter, primarily due to planned workovers in Canada that we can only do during winter access and which those were accomplished. Lastly, the first quarter has higher production advolerm taxes but this is mainly attributable to the fourth quarter being arbitrarily low as a result of having our over accrual of the advaloren taxes for 2006 that we recognized in the fourth quarter.

Turning to Slide 25, we talked about capital invested for the first quarter, we did invest about $508 million, as we talked about, you know, in our first call in February, back in February, we did announce by let everyone know that we were going to have our capital budget for 2007 being heavily front end loaded with significant capital being spent on our development projects, that being [oogeric and Southcoast gas].. We also knew that we had a heavy winter access drilling progam in Canada and then in the NPRA in Alaska. So, if you take those four items on a combined basis, that represents about $237 million of the first quarter's capital spend.

And so those, obviously being will come down drastically as we move through the second half of the year. For the remainder of the year we really look at the bulk of our capital being concentrated on the lower risk development drilling in Spraberry and Raton and to the further the work in our resource (inaudible) in the Edwards trend inTunisia that Tim talked about.

Turning to Side 26, where you see our open hedge position, as Scott mentioned that we have been active in adding hedges in the first part of this year. Specifically we added about 140 million cubic feet per day of 2007 gas hedges at $8.25.

We also added about 7500 MCF per day of 2008 gas hedges at $9.25. On the oil side, we added about 4500 barrels per day in 2007 with collars at 63 by 76. We also added in 2008 and 2009 bout #500 barrels and 5,000-barrels per day, respectivelly, using swaps at over $70 a barrel.

And as Scott mentioned we do look to continue to captuer, the run up in prices -- as we progress through the remainer of the year, particulary in '08 and '09. Switching gears to Page 27 where we talked about second quarter guidance. I think as we -- as Tim mentioned, you know, the weather-related problems are behind us.

We do expect the production grow pretty substantially in the second quarter but more so in the second half that I will talk about in a few minutes. And so we are having guidance of 100,000 to 106 BOEs per day for the second quarter, most of that coming from the Spraberry, Raton, Edwards, and Tunisia areas. Production costs are expected to be $11.25 to $12.25 for the second quarter, similar to what we experienced in the first quarter.

Exploration abandonments are expected to be $50 to $100 million, with $30 million of that range being associated with the West Africa, Nigeria well going down in the second quarter and carryover costs related to our Alaska drilling extended into April. D & A is expected to be $10 to $11, similar to the first quarter, G&A is expected to be $30 to $34million, down slightly from the first quarter.

And interest expense is expected to be up from the first quarter, at $32 to $35 million, primarily associated with the incremental borrowing that has occurred as we spent money on our front end loaded capital program. Cash taxes are expected to be $5 to $15 million, primarily associated with taxes that we will pay in Tunisia.

And our effective tax rate is expected to be 37 to 55% with the upper end of that range reflecting the potential of having an unsuccessful Nigerian exploration well for which we wouldn't get a tax benefit currently, we will eventually get one but it will just come down the road. And secondly, assuming that well is successful, then our tax range, would be 37 to 45%, as has been the normal case for the past couple of quarters. Turning to Slide 28, we talked about second half production growth.

As you can see in this slide, we wanted to point out where we are see production going from this point forward for the rest of the year. And the second half growth driver in the middle of the page. It points out that most of the growth is back ended loaded for the year.

Most of it is coming from our low risk development drilling program in Spraberry and Raton, where you can see some bumps coming later in the year. We also have the start-up of our South Coast gas development project, which is virtually complete now and we will start up in the second half. We also have continued growth coming out of the Edward and Tunisia areas that Tim talked about.

So we remain confident that, you know, these projects can and will add about 13 to 15,000 BOEs per day of incremental production during the second half of the year. And that the result in a double digit production growth rate for 2007 as compared to 2006 and we look forward to giving you updates on these as we progress these projects for the remainder of the year.. So with that, I will turn the call back to the moderator and we'll open it up for questions.

Thank you. (OPERATOR INSTRUCTIONS) Our first question is from Robert Morris from Bank of America.

Good morning.

Hey, Bob. How are you doing.

Good. A couple questions. On the incremental $450 million share repurchase program, over what period do you plan to conduct or complete that?

We are to the committed to a specific time frame, Bob. We watch to reduce shares over time and we went to be optimistic as we see dips in commodity prices. We just want to make sure that we have the fire power out there. So you can see we bought some first quarter. We bought about 9 million shares last year. I'm just not going to commit to a price or a time.

Okay. Second question, sort of related to the MLP, from the old Parker and parsley assets on the NOL, there are there any Rule 382 restrictions on timing of use of those NOL's as far as sheltering tax as far as sheltering tax from distribution funding the MLP?

We have most -- most of the NOLs were used up back when we did the Deepwater sale. We have $80 to $100 million on NOL's that did have limitations on and those run off about $20 million a year.

Good. Thank you.

And moving on, we will take a question from Brian Singer from Goldman Sachs.

Thank you. A couple of questions on Spraberry, first, the additions of the Wolfcamp? Is that already booked as (inaudible) in your Spraberry inventories and (inaudible) or is that is up side.

It's up side. Brian, this is Scott. Also we don't discuss it much but we are making several Wolfcamp only wells that are coming in much greater than the 20 barrels a day or 20,000 barrels per day and so we will produce those for a while before we add the Spraberry Dean above it.

What total up side would you see based on what you are seeing so far from the Wolfcamp?

Right now, we stated 20,000 barrels for a while. So it takes you up from 110 to 130,000 barrels of oil equivalent. So, you know, some of our wells throughout the Spraberry are already down to the Spraberry Dean. So if we go back in and do some infield drilling, we will be into the deeper Wolfcamp also. We are also testing this year -- taking the Spraberry down to 20-acre spacing also.

Great. And just strategically, how does your decision to grow the Sprayberry field or to increase drilling versus your original plan for the year? How does that jive when you look at the longer term growth rate for Sprayberry and more of an MLP structure?

Well, before MLP came about the Spraberry trend area we have over 4,000 locations that excludes 20 acres, excludes potential water flooding in Sprayberry and also we are probably adding at least 500 locations per year. So as we add locations, it's important to shrink the price and also drill -- shrink the probables at the same time, we will be adding. So, you know, we are confident it's going to grow 15 to 20% per year. The MLP, obviously, we can't discuss the amount of barrels or production we are moving out, but the process is to move as we need capital. Is to move out some of these proven and producing properties.

Great. So we should not expect that type of rate of growth for the Spraberry portion of the I.PO, I understand.

No, we can't talk about growth rates inside the MLP.

Great. Thank you.

Our next question come today comes from Ellen Hannan from Bear Stearns.

Good morning, a couple of questions. I'm not sure if you can help us with this or not. In terms of why you are outlook for '07 through 2010, kind of the production per share growth target of this 12% plus range, how should we think of that in terms of the impact on potential share buybacks in that number and/or the volumes that you are planning to potentially move into your MLPs?

Yes, right now the 12% production per share growth rate excludes the two divestitures. So the first two IPOs are excluded from that. They are taken out. So we are still able to grow and increase our 12%. It does not include any other divestitures into the MLP. Our growth rate, based on what we see with Edwards, Spraberry and Tunisia, we feel very confident that we can deliver on the 12% production per share. Obviously we have the ability to buy back more shares during certain time frames. We pay see higher growth rates as we see Tunisia and Edwards continue to progress. We hope to be upping that rate over the next three to four years.

Now does that rate anticipate share buybacks, or no?

That rate, the 12%? Yes, it does anticipate some buybacks.

Also again, not to harp on the MLP, could you give us an idea in terms of when you sell assets to the MLP, how do you create that that's an arms length transaction and in so doing, does that allow you to step up the basis for the assets to create the tax shield within the MLP?

That's one question I will not be able to answer until late June or July when we file third quarter.

Okay, thank you, that's it for me.

We move on to Robert Christensen from Buckingham Research.

Yes, noticeably absent were your cold bed methane pilots in the Rockies. Can you please give us an update on those?

Yes, Bob. They are still progressing. It just doesn't have a major impact on production at this point in time. They are progressing. Their rates are increasing, and we'll be making a decision on those by the end of this year.

Question on the rigs for the Edwards reef. You are adding another rig. Is that a company-owned rig, I can't remember. You were buying some rigs, I thought, for -- back at your analyst day. Can you just give me some information on the -- on the rigs and their availability kind of thing?

Yes, Bob. This is Tim. We do have several rigs that are actually in the second year of three-year leases that would be the subject of that drilling campaign and some well-to-well obligations in play as well. Really having no issue finding rigs and the rigs that we are speaking to as to the schedule of upcoming rig additions are already contracted. So we are in good shape on that.

Great.

Anything further Mr. Christensen?

No thank you.

Thank you. We'll move on to Sven [Del Pozzo] from John Herold.

Hi. How are you doing.

Fine, Sven, how are you doing?

Good. I was just wondering with your 12% (inaudible) for '07 to '10 per share, is there a corresponding value for what the midcontinent fields might -- how they might be factored into that number? In other words West Panhandle and (inaudible), I'm wondering what the relatively mature state of those assets. Is there a -- how do you foresee or forecast what the depletion rate of those fields is when looking at '07 to '10 compound annual growth rate?

If you recall most of the (inaudible) volumes were in our volumetric production payment. And they are fairly flat. And then they have a big jump in 2010. But it comes back to us. West Panhandle, we delayed our infield program this year. We will be stepping it back up in '08, '09, and west Panhandle will be kept fairly flat through a slight decline. That's how we look at it in a four-year model.

And forgive me for patching in late, but did you mention from '07 to '10, which years might have the -- I mean is that a back-end loaded kind of production growth on an absolute basis that's will generate a 12% average per share from '07 to '10, or is there any color on the timing of absolute production volumes between the '07 and '10.

Yeah, I think you can tell by just our slides.

Okay.

That Tunisia is going to have a big impact in 2008, 2009. Alaska is going to a big impact in 2008 and 2009 and South Coast Gas is going to have a big impact in 2008, 2009 While Spraberry and Raton will continue to plow along at their current growth rates.

Thank you very much.

Our next question will come from David Heikkinen from Pickering.

Good morning. Tunisia, whenever you went from 2D lines to the 3D. Can you give us a though of how the prospects, how many got upgraded and how many got dropped off. How many 2D prospects had you and then you talked about numbers of remaining prospects outside that are on 2D and thoughts about how 3D will affect those prospects.

We don't have an exact number of how many dropped out. The only thing that I do know, David, is that several got bigger. Several materialized to where they became drillable status. I don't know if Tim mentioned but important messages that we still have probably only shot about a third of our acreage on 3D. So we will be probably be shooting 3D on our acreage over the next two or three years and extending it both on VEK and Jenine nord.

The kind of thought process of concentrating drilling on those larger prospects. I'm trying to get my mind around how Tunisia grows over the next three years. Will it be lumpy project development or is it just kind of steady wells that just come in throughout the years?

Well, we have a rig that's operated and we have it for a two-year contract. It will be drilling both exploration, -- low-risk exploration prospects and development, appraisal wells off and on over the next two years. The one thing we didn't really focus on is that we have a third of our rates or gas and condensate. When we mention or test wells, and so we are leaving all of our condensate and gas shut in, we are producing some gas, very small, but we anticipate a large gas condensate project sometime in 2009 to 2011 inside Tunisia. It's a big project that we are working on with E & I. That will have a big impact also later on.

The -- maybe another way to ask it, are there any facility constraints as you see facility expansions that come in that then give you wedges of production growth.

Well, you are not going to see -- that's why I think Tim mentioned -- or if he didn't --

Until the end of this year.

Yeah, the fourth quarter.

And the same thing will happen in 2008, 2009, 2010, as you get facilities on, I'm just using the analogy of Anadarko Algeria where you do a facility expansion and then you see a wedge of production. Is that a similar model in Tunisia.

It will probably be a little bit quicker. Jenine nord, you basically have a six to nine month delay, based on installing the first set of facilities, add on that we're going into existing facilities. As we go further away, with new 3D, and step out, we will have to build new hubs. And so you will see some delays if we have success as we move further and further out.

That's helpful, I was just trying to visualize it. Thanks.

We'll take our next question from John Herrlin from Merrill Lynch.

Yeah, hi. Most things have been asked. I want to reconfirm what you said on your production growth, Scott.

Yeah.

You are excluding the M.LP volumes and the 12% growth as same-store sales.

Yes, we took out the -- assuming divestitures happened in 2008, or the IPOs so they are out so we are still hitting 12% production growth per share.

Cool. The next one for me is Nigeria. What is the dry hole cost associated with those commitment wells.

It's about 20 million on the first one and about 30 on the second one.

And say they are good, is this something you would then, you know, ultimately sell or develop?

I would guess that if we do have success, that the goal -- the strategic goal would be to divest.

Okay. Thanks.

Okay.

And we'll take a question from David Tameron from Wachovia.

Good morning, Scott at Edwards Trend you are increasing your cap. By 60 million.

Yes.

And you are saying additional 10. What is the difference between wells and infrastructure as far as that 60 million.

Tim, do you have an exact split?

We are going with more wells. 10 additional wells is going to be --

I guess what -- what are the Edwards wells running right now.

They are running about 3.5 to 4 million if we use the -- the, did you mention the packers plus, yes packers plus will take it on up another $500 to $700,000.

So you are talking about somewhere in the neighborhood of $40 million in drilling.

Okay. And then $20 million of infrastructure. Then where are you at once the new infrastructure is in as far as capacity and going forward in Edwards.

Well, we're talking about doubling our capacity, our current capacity in processing is 60 to 70 million a day, and so we'll be doubling that.

So that should hold you for a while.

Right.

I know the answer but I will ask it anyway. Do you need a -- do you need an IRS tax ruling for the E & PMOP and if so, do you have that already.

Yes. Not to my knowledge, we don't need an IRS tax ruling.

Okay. Thanks.

We'll move on to a question from Rahan Rashid from Friedman Billings Ramsey.

Good morning, Scott.

Edwards Trend and Tunisia. You did mention that maybe there's some up side to your 12% guidance. I'm going to presume that most of that incremental upside could come from these two. Could you walk us through as far as timing or just thought process as far as what has to happen for us to see further up side to your 12% growth, and then I have a follow-up question. Yes, on Tunisia, it will be solely focused on the success of seven or eight more exploration wells, both being drilled by us and E & I. So we will know something over the next 12 to 18 months.

Okay.

That will drive it. That's excluding the gas condensate project that I'm talking about, which will probably come on after the '07, '10 horizon. Edwards, we are going to start drilling some, it's really the completion of our 3D and that will be over the next six to nine months. And so we will drill several more key low-risk exploration prospects. Probably in 2008, late 2007. So it will probably take another year of drilling to see whether or not Edwards can expand even greater.

Got it. And speaks to what your TCF or reserve upside that you talked about at your analyst conference, so by early '08 we'll have a good feel for how much of that could materialize.

Yes, probably about late '08 on Edwards.

Okay. Perfect. On your Slide 6, you do talk about your cash flows going to 1.6 to 1.8, that's April strip pricing. Could you act -- what is the rough number in terms of commodity prices.

Yes, its about 65 to 66 on oil and about 825 to 830 on the gas strip over the next several years.

Got it. And in terms of if I was to try to I splice up the cash flows by area, call it U.S., Canada and international, any thoughts on that front, how -- what would be the rough split?

Well, it's going to be more oil focused, as I mentioned in the first. Sprayberry is oil, Tunisia is oil, Southcoast Gas is based on oil, 10% of (inaudible). And Alaska is oil. So the only gas will be the Raton growth and the Edwards growth.

I was actually more thinking about break down by area. So U.S. would be, what, two-thirds of these cash flows? Any rough thought on that one or I can do the model myself.

I will let -- I will let Frank get back with you.

All right. And similar thoughts in terms of out in '10, any guesstimation for what your maintenance CapEx would look like for a 1.6, 1.8 kind of cash flow number?

It will increase significantly, obviously.

Sure.

It won't be 500 million any more. It will probably obviously get up to 800, 900 million range.

Okay. Fair enough. Thank you.

Okay.

And up next is Ted Izatt from Bear Stearns.

Yes, hi Scott and Tim, congratulations on your quarter. You mentioned you wanted to maintain financial flexibility. I'm wondering was that specifically referring to the Pioneer level or the MLP level or both.

I'm referring to the Pioneer level.

Okay.

Obviously we can't discuss whether or not the MLPs will -- and their financial flexibility.

Right. And then second, I was -- I guess with the M.LPs, as you put assets in there and then as do you your acquisition strategy, you know, you said you want to put the more proven, I guess the reserves into the M.LP and then have Pioneer take on some of the development stuff. Would you modify your capital program accordingly with that or your leverage levels with increased risk there, or how do you see that playing out?

No, if we are successful in acquisitions, and Pioneer buys the undeveloped, we will be increasing our rig count, most likely inside Pioneer, while the MLP buys the developed assets. We're still going to maintain strong financial flexibility inside Pioneer and if you look at that cash flow slide, with our cash flow, essentially doubling over the next four years, we've got strong financial flexibility.

Okay. Thank you.

Our next question today is from Vivek [Pau]l from UBS.

Yes, good morning. What do you expect your leverage to be by the end of the year and how do you plan to fund that? Do you just bank that or a hybrid or something in those securities that could (inaudible)?

Yeah, this is Rich. We look at our debt-to-book still at the 40% level at year end and, you know, funding will come from our credit facility, which we got out there, or the bond offering back in March and that's done and behind us. And so it will come from our credit facility.

And the shortfall should be about 500 million this year?

Yes, our cash flow somewhere in the $800 to $900 million that we talked about and our CapEx budget is about 1.3. So it will be that delta.

And the stock buybacks? They will be also from the bank facilities, right?

That's correct.

So that will be another -- I'm just trying to get to 500. So the CapEx and OCF alone is 400 and then stock buybacks how much do you plan to do.

Yes, and we were not out there predicting what that level of stock buybacks would be, it depends on where commodity prices go and what our stock price does.

Okay. And second, what steps are you taking to firm up your ratings that have been under pressure because of all the recent developments. Is that not a priority near term, I know long term it will be okay.

I think Scott mentioned we continue to want to keep our balance sheet strong and keep our financial flexibility. We will continue to manage the company in a prudent manner and, you know, the rating agencies they'll do what they need to do. But we will keep our balance sheet strong and financial flexibility.

And when you say strong, it means debt-to-capital at 40% and $2 billion in total or is that -- how do we define strong.

I think we will keep our coverage ratios at a good position as well as keep our debt-to-book in that 40% or below range. Long term, we'd still like to be in the 35% level.

Thank you.

Sure.

And our next question is a follow-up question from Robert Morris from Bank of America.

Hey, Scott, real quick, I neglected to ask you, what is your tax basis for your Spraberry assets?

I don't -- Bob, this is Rich. I don't have the exact number here with me. Obviously we drilled most of those wells so it will be fairly low.

Fairly low, okay good. Thank you.

And that does conclude our question-and-answer session today. Mr. Hopkins, I'll turn the call over to you for additional or closing remarks.

Thanks everyone for joining us. If it there are follow-up calls, please call me or Scott Rice. We'll be glad to work with you on those. Thanks again everyone for joining.

That does conclude our conference call for today. Thank you all for your participation.