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Frank Hopkins - VP of IR

Scott Sheffield - Chairman and CEO

Tim Dove - President and COO

Rich Dealy - EVP and CFO

Analysts

Michael Jacobs - Tudor, Pickering, Holt

Gil Yang - Citigroup

Brian Singer - Goldman Sachs

Scott Wilmeth - Simmons and Company

Jon Wolff - Credit Suisse

Leo Mariani - RBC

David Tameron - Wachovia

Rehan Rashid - Friedman, Billings, Ramsey

Chitha Sandara - Cardinal Capital

Pioneer Natural Resources Co. (PXD) Q2 2008 Earnings Call Transcript August 5, 2008 11:00 AM ET

Operator

Thank you for standing by, everyone. Welcome to Pioneer Natural Resources’ Second Quarter Conference Call. Just a quick reminder, this conference is being recorded.

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. Once again, the internet site to access these slides related to today’s call is www.pxd.com. At the website, select Investors 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 Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in the last paragraph of Pioneer’s news release, on page 2 of the slide presentation, and in the most recent public filings on Forms 10-Q or 10-K made with the Securities and Exchange Commission.

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

Frank Hopkins

Good day, everyone, and thank you for joining us. Let me briefly go over the agenda for today’s call. Scott will be our first speaker. He will review the financial and operating highlights for the second quarter of 2008, another strong quarter for Pioneer. He will then comment on the company’s outlook for production and cash flow over the remainder of this year and talk a little bit about what happens post 2008.

After Scott concludes his remarks, Tim will review the performance of the key assets in the second quarter, and the expectations over the remainder of 2008. Rich is then going to cover the financial highlights for the second quarter, and he will talk about and go through the guidance that we are providing for the third quarter of 2008. After that, we are going to go open up the call for questions.

Before turning the call over to Scott, for those of you interested in the second quarter results of Pioneer Southwest Energy, our recently formed Master Limited Partnership, there is a conference call scheduled at 11:30 a.m. Central Time, after this call is over.

With that I’ll turn the call over to Scott.

Scott Sheffield

Thanks, Frank. Good morning. Slide number 3 on financial highlights. Pioneer reported second quarter net income of $159 million, over $1.32 per share. Second quarter production continuing to grow, 114,000 barrels of oil equivalent per day. It’s up 19% versus a year ago second quarter of ‘07. Did increase our capital budget from $1 billion to $1.3 billion, primarily due to response and improved drilling efficiency, that’s primarily more in the Spraberry Trend area in south Texas where we are drilling more wells per rig and we have had our crews working on these rigs now for a good two years.

Continued operational success and obviously rising costs primarily due to steel, pumping services, and fuel, so we have seen in the last few months. Our production growth target in ‘08 has been increased from 14% up to somewhere between 18% and 20% for the entire year versus 2007.

First half discretionary cash flow increased 45% versus first half of 2007. And obviously, we still feel like it’s important to have a free cash flow model as we do in ‘08 and beyond, even with this recent CapEx increase. We did IPO our MLP Spraberry reserves and received net proceeds of $160 million during the quarter.

Slide number 4, operational highlights. Again driven by strong production growth, consistent and strong production growth, up 21% first half of ‘08 versus first half of ‘07. Primarily in several areas, Spraberry Trend area. I mentioned the first two items, drilling and operational efficiencies.

We are also starting to focus a lot of our wells on the west side of the Spraberry Trend area field in the Wolfberry Play where we are making several wells up in the 100, 150 barrels a day in those areas. In addition, the Raton continued Pierre Shale drilling success and integration of our fourth quarter ‘07 acquisition.

In the Edwards, again, drilling efficiencies primarily due to casing design changes and also rig crew efficiencies. We are drilling more wells there, higher rig wells, and also with infrastructure expansion coming in, which Tim will give you more details about. Tunisia, more discoveries there in Tunisia and infrastructure expansion. And then Alaska, Oooguruk came on earlier than we anticipated in June of the second quarter.

In addition, we are getting very encouraging results from several themes in the Spraberry Trend area and also the Raton Basin. Spraberry Trend area, very encouraging results continued with 20 acre drilling. Also, our horizontal reentry program where we went back in and did a Packers Plus type frac job, did some older horizontal wells, seeing very consistent flat production. And then, with recent coring and shale interval testing, I think all those results combined tells us that there is a lot of oil and gas left in the Spraberry Trend area.

In addition, we confirm contributions from two additional zones; Kp2 and 3, in the Pierre Shale, which Tim will give you more details about. We think over time, obviously, that will add more and more reserves in the Pierre Shale. Followed up by three more successful Tunisia discoveries, two by ENI and one by PXD.

Slide number 5, again, on production growth. Still delivering very consistent production growth. As you can see, back to 2005 through second quarter of ‘08, again, we are up 19% second quarter versus second quarter, first half versus first half up 21%.

Slide number 6. Where were the increases in our CapEx, again, as I mentioned, they were primarily due to drilling efficiencies in Spraberry and Edwards. They were not due to adding more rigs; essentially, we are drilling more wells per rig. Success capital - with continued success in the Edwards and our Cosmopolitan project up in Alaska. And then, again, rising costs, primarily, as mentioned steel costs, fuel and pumping services.

Pretty much spread out, Spraberry Trend area is getting almost half of our CapEx of $1.3 billion. And following up, obviously, we increased our production growth target up to 18% to 20% up from 14%, and still generating free cash flow with this model.

Going forward over the next several years, obviously, we’ve had a significant increase in 2008. We feel very confident that our program will continue to deliver greater than 14% per share. Assumed no additional share repurchases. In addition, we will be having significant excess free cash flow during those years.

Slide number 8. We have updated our returns with a combination of both changes in prices and also with a little bit higher cost as we have seen. Still very, very strong in terms of rate of returns, these are before tax, and strong DROIs. Strong cash margins, obviously, in all of our key assets with oil, obviously, benefiting stronger margins because of where natural gas is trading. Again, very, very strong returns at both price decks that we show here.

Slide number 9. Obviously, we are going into a very, very strong cash flow growth in 2009 coming out of a strong 2008. We are targeting another 50% cash flow growth in 2009. Obviously, that’s driven two-thirds by production growth and one-third by legacy hedges expiring.

Still generating free cash flow in ‘08 and beyond, more in 2009. Again, increasing 50%. And again, return on capital employed increasing significantly as the hedges roll off in strong growth. Again, earnings doubling in ‘08 and quadrupling going into 2009, as compared to 2007.

Summarizing, slide number 10, investment highlights. Obviously, we are on target to continue to exceed 14% production per share growth through 2011 that we have laid out over the past year. Again, a large drilling inventory in all of our key growth areas. Very repeatable growth. 2009, obviously, is going to see another big jump as we saw from ‘07 to ‘08.

We seen another big jump in cash flow going from 2008 to 2009, up 50%. We still think it is important to generate free cash flow in 2008 beyond. Huge resource base to depend upon. Again, net asset value at $85 and $100 oil. We are still, obviously, trading way below net asset value with a lot of upside in our stock price.

Let me turn it over to Tim to go over operational successes.

Tim Dove

Thanks, Scott. As you’ve already mentioned, Pioneer had another strong quarter from an operational standpoint as evidenced by our production growth. And what I will do is update you on some of the key operational areas and their performance and also give you a feel for the progress we’ve made on some of the resource initiatives across the company.

First let’s start with Spraberry on slide 11. Of course, Spraberry is a giant oil field that’s getting bigger and really the objective is to increase our recovery rates in this 30 billion BOE in place field. That’s what you will see is the basis of all our objectives is to unlock our share of that net resource potential, which we, today, estimate to be about 1 billion BOE net to the company.

So several initiatives are ongoing and we’ll give you some data on those. First of all, we continue to progress our 40 acre drilling campaign; that’s been the basis of drilling over the last several years. We have about 200 million barrels un-booked on a 40 acre spaced field rule. We have drilled about 50 of the un-booked locations so far this year, including deepening the wells to the Wolfcamp. In addition to which, we have drilled about 175 currently proved undeveloped locations so far this year, such that our total campaign so far has drilled about 225 wells.

We also are getting focused on and are advancing our 20 acre space drilling campaign. We estimate the resource potential there to be about 500 million BOE net to the company. We will be drilling about 25 wells this year based on 20 acre spacing. And the first three wells we have already drilled and produced for over 120 days are giving us a lot of confidence to support the view that we’ve already expressed, which is to say that the 20 acre locations, we believe, will produce at least about 70% to 80% of what a 40 acre location will recover. And the economics on that, of course, in today’s oil environment are excellent.

We’ll probably drill double that number of wells, say, in 2009. One of our major objectives this year is to apply for field rule changes with the Texas Railroad Commission. We’ll be making that application, here, a little later in the quarter and that will allow for optional 20 acre down-spacing in the field.

In addition, we are making some progress on our Waterflood project. We are past the idea of a pilot at this point. We are going to be putting in place two large scale projects in two units. We have about 12,000 acres identified for these projects. And waterflooding, in and of itself, across the field areas we think it applies may add another 300 million barrels of resource potential.

We are going to be planning a 20 to 35 injection well campaign for 2009. We will probably be preferring new wells for injection rather than unnecessarily converting some of the old wells, but there will be some conversions of existing producers into injectors as well. We will be constructing facilities for the injection during the first half of the year, which of course includes tankage and flow lines and pumps and so on.

The objective, which is to begin water injection third quarter of next year, and then we anticipate, as has been typical, in ten prior waterfloods a response in the neighborhood of six to nine months after injecting water.

Then turning to page 12, a couple of new initiatives that we have been referring to, and Scott mentioned as well, that are really not captured in the 1 billion barrel resource potential we have already identified on slide 11. These are in the early stages of analysis, but are very interesting and hopefully can lead to increasing our resource potential as we get more data. What’s important to emphasize is this is early days in terms of our understanding of the applications in horizontal drilling and the shale interval potential.

Let me take you through some details of what we have been doing. In the ‘90s, of course, Parker & Parsley drilled over 20 wells, horizontal wells with open hole completions, and these typically had 700 to 1100 foot lateral sections. What we’ve done is to go back into these wells using isolation packer technology and frac four stages in each well, and what we are seeing are dramatic increases in production.

These wells, typically, after many years had been reduced down to making 3 to 5 barrels a day and on average those wells are now making 30 barrels a day. So what we’ve achieved is a about a six-times increase in production and it’s holding relatively flat. So it is not seeing the typical hyperbolic declines you would see in a typical vertical well, and so it is possible here we have tapped into new resource potential by the application of new horizontal technology.

We are going to continue the efforts here. We plan to frac two additional wells later this year, and I think we are going to put five new wells in for 2009. The idea is to evaluate the applicability of horizontal drilling in certain subsurface applications, as well as when we have certain surface issues we are trying to avoid, horizontal wells may have applicability.

Our early evaluation of the shale interval potential is continuing in this field. Realizing that Parker & Parsley and Pioneer on a combined basis have now drilled something under 6000 wells and they have all been completed essentially the same way, in the traditional sand silk intervals.

What we’ve done is to go back and look at how these wells have been completed. And recently we have drilled two vertical Spraberry wells that have actually tested the nontraditional shale silting intervals. That was based on the log characteristics that we saw in evaluating those wells.

So what we’ve done is, essentially, to complete and frac in different areas, different pay zones, than we had traditionally done over thousands of wells. And interestingly, after four months, the first well of the two is producing still about 50 BOE per day which is better than the two offsetting wells that are drilled in the more traditional sandy intervals. And those wells typically are making 20 to 30 barrels of oil per day when looked at on the same time frame.

What we are doing now is analyzing the core we took from the second well, it’s a 650-foot core sample, it is about 90% shale. This shale is ubiquitous across the basin, has different thicknesses in different areas of the basin, and typically it’s [interbedded] with siltstones.

So, the objective now in the future will be to take more core barrels, but the objective with the current core is to evaluate it by the end of August and that will give us some direction in how to take our core program in 2009 and 2010. And this second well, it will be interesting to see when we complete this well in both the traditional sand rich intervals as well as the shale intervals, as we get into the latter part of the quarter.

In addition, I think we are going to plan to drill a couple more wells to do the same, which is to test both the sandy traditional intervals and the more shale oriented intervals as we get to the end of the year. We will also be using tracer technology to identify really where this oil is coming from.

It is a very interesting project. I think the important point about it is it is very, very early days as well on the project. But the whole objective of these projects is to continue to work on the unlocking of the potential in the field to increase recovery rates because you have here a giant field getting bigger.

Slide 13. This gets back more to operations on Spraberry. Very strong production results. Scott already mentioned our rig efficiencies. Each rig in this field is now drilling in the neighborhood of two wells per month as compared to 1.8. It is a fact that our hands have now been working on these rigs for many months, couple of years in fact. We are starting to see tremendous efficiency, so we are simply drilling more wells with the same number of rigs.

We have added one rig. We are now operating 17 rigs in the field having added one recently, and that is preparing us for a 20 rig campaign in 2009. We have increased our production growth target due to these efficiencies and due to the outstanding results to the drilling. We would anticipate as a result of ramp up in drilling we are looking at over the next few years, that the Spraberry CAGR of 15% will be doable as shown in the chart on the bottom of page 13.

Now turning over to Pierre. It’s another major area of focus for us, this is slide 14. We have two specific initiatives underway. One is to test the Kp2 and 3, this is moving up-hole from the Kp1 testing that had been done earlier in this program, and secondly, to test the viability of horizontal drilling.

As we have already stated publicly many times, we believe the Kp1 vertical completions in and of themselves are economic and have been very successful. What we are trying to do in this situation here is to enhance the economics of a vertical well by evaluating upper zones and vertical drilling.

And so far, what we can say is from five wells we have seen contributions that are positive from the Kp2 and 3. In fact, we believe that the additional zones can contribute incremental production of about 20% to 30% on a sustained rate when just compared to a Kp1 completed well. And the incremental costs to complete in those two zones is about $300,000, which essentially is just the fracing of the two additional zones.

What’s important to note is our initial horizontal drilling campaign is just underway. We are going to be drilling two horizontal wells back to back with 2,000 foot laterals and we are, obviously, looking forward to the results of that campaign and we will get back to you with how those wells do.

And turning to slide 15. This is Pierre operational results. Production growth is on target. We are going to be drilling about 175 wells this year, of which about 15 will be Pierre. And we are on target from a drilling campaign standpoint. Production this year should be up a little over 15%. Third quarter production will be essentially flat with the first half maybe slightly down due to the fact we have got some substantial field compression maintenance work going on in the field in the third quarter.

We will be adding to the drilling campaign getting into 2009. And we believe with the contribution from the Pierre Shale we can increment the longer term Raton production growth rate to 10% to 15%, and we have confidence in that in showing the fact that we are now adding firm transportation beginning a couple years to take Raton gas to the west coast to reduce our dependence on pricing and differentials in the Rockies and Mid-Continent markets.

Turning to slide 16. Edwards Trend. We are making very good progress on building out our infrastructure in the Trend and completing the large 3D seismic shoot that is the basis of future of drilling. Second quarter production was up only slightly as we expected because we have several wells still awaiting tie-in, these are relatively high-rate wells that can have an impact once we have the infrastructure in place. And we’re making significant strides toward that end.

We will be increasing the number of wells we drill. We have a very similar situation here as we do in Spraberry where our incremental rig improvements and wellbore designs have led to the number of wells per rig increasing, and that just leads to more wells being drilled with the same number of rigs.

And this is really paying attention to minute details to avoid problem areas in drilling wells that we have had a great deal of success in doing and anticipate that will continue. We will also, in the second half campaign, be drilling three new well – sorry, three new field prospects. We are about three quarters of the way through with our seismic program across the Trend. Very large shoot, of course, that will be completed we believe near the end of this year.

We are increasing our production growth. Went into the year with about a 25% increase in production planned for ‘08, now it looks like greater than 40%. Our current production is greater than 75 million cubic feet per day, it’s between 75 and 80 as we have gotten some of the infrastructure builds done during the second quarter and we’re starting to bump up production. But we still have substantial production curtailed and shut-in as we wait for the remaining infrastructure in ‘08.

We have about 20 million a day shut-in today waiting on the infrastructure, and we anticipate adding between 20 and 45 million a day gross treating capacity between now and the end of the year. That will probably take the form of several amine treatment plants being added in the field. And we will also be adding substantially to capacity next year as we continue the ramp-up and drilling in the Trend.

On slide 17, the Barnett Shale is starting to see the expected results from our operated drilling program as we anticipate ramping up drilling in 2009. Importantly, we have now drilled about seven wells in our operated area of Parker County with excellent rig performance. We have had a couple of initial wells flow-back at greater than 2 million cubic feet a day.

Overall, the results look like they are in line with other Parker County type wells, meaning they average about 1 million cubic feet a day in their first peak month of production. We are keeping our drilling costs under control as we, again, are seeing the benefits of operational efficiencies and rig efficiencies reducing the number of days on a well.

We have – let’s put it this way. We are well on the way to contracting our rigs for a 2009 campaign in Barnett Shale. We are very close to having those deals signed to add three rigs net so as to have a total of four operated rigs in 2009. And we are still anticipating Barnett can be a major contributor to the company’s growth as we look ahead to the next several years.

In Tunisia we have had a continuation of our successful drilling campaign and progress on infrastructure here, as well, as we have built out more infrastructure in the second quarter. In fact, we were successful in increasing our infrastructure build-out to about 10,000 barrels a day in Cherouq which was a major targeted effort for the second quarter of 2008.

We drilled three successful wells. Actually each in the two areas, Cherouq and Adam, as well as BEK to the south where we tested a high rate gas and condensate well, I’ll mention more about in just a minute.

We have several wells planned for the second half of the year. Importantly, two of those are in the Anaguid block, as you look at slide 18 they are in the blue area to the north. These will be the first wells to test the producing intervals that we have seen down in Adam and Cherouq, and we are watching with a great deal of anticipation for how those wells do.

We now are at the point where we have completed our major 3D campaigns, this is across our acreage, and we can confirm we have got a lot of prospects that have been generated from that. So we will be anticipating that will be the basis of future of drilling campaigns.

Overall production is doing well in the field. Our net production from our three operated areas on a BOE basis is about 7.5, 7,500 BOE per day. Cherouq itself has now been moved up to 9,200 BOE per day, of which, of course, Pioneer has 50%, and then slightly reduced for royalty.

We do have three wells that are currently shut-in, that are waiting on the capacity limitations that will be the subject of capacity expansions during the fourth quarter. We anticipate moving that capacity in Cherouq up from 10,000 barrels a day up to about 20,000 barrels a day in the fourth quarter and that looks like it is on schedule.

Then slide 19. Just a little progress on our longer term gas project in Tunisia is noted on this slide. There have been several discoveries made in the southern part of the country where Pioneer operates, along with several other major operators, and those operators have now combined a consortium to evaluate the possibility of putting in place a gas pipeline to go to the northern port of Gabes, industrial areas in that area. It’s about a 200 mile pipeline to the gulf. We are evaluating that with those operators with the idea of a feed study to determine putting in place a project say 2011, 2012.

Importantly, there have been a couple of really critical discoveries that lend credence to the idea you’ve got lots of gas in the area. The Abir 1 Discovery, in BEK, that’s the well I mentioned that produced high rate gas 17 million cubic feet a day and 1,000 barrels of condensate a day with Pioneer and its partners in the BEK block.

Also, OMV, separately, in the area shown between Pioneer’s purple BEK block - essentially BEK surrounds the area that’s become drilled - they made a significant discovery, 120 million cubic feet a day and 3,500 barrels a day of condensate. That gives credence to the possibility of a longer term gas project for the region.

On page 20, we’ve got more definition now on the shut-in of the gas producing injector well in Sable and then the conversion of it to actual gas production and we anticipate that the Sable oil field will be shut-in here at the end of the quarter, that is the end of the third quarter, and after it is shut-in it will take a couple of weeks to convert it to a producing well. It will be on stream during the fourth quarter.

The way this will work, we will see a ramp-up of production the well will be put on and gradually increased. The majority of the major increase will be seen once it’s been on a few weeks and probably the peak production we will be seeing from the new well as we get into the first half of 2009. We are, obviously, benefiting here from the fact that we are getting very strong prices for both oil and gas in South Africa owing to the fact they are tied to Brent.

And my last slide is slide 21. Scott mentioned the fact we have put production on early June. We are very excited about that. Pioneer is now the first independent operating an oil field on the north slope of Alaska. The production did come on early, which we’re very happy about.

For the time being, as everyone knows, we are not producing oil as the onshore facilities that processes this oil are under maintenance. That is anticipated to be finished at the end of August and we’ll be cranking up production at that point. Still anticipating on a net base business about 3,000 to 4,000 barrels a day at the end of the year, and increasing to peak rates of 10,000 to 14,000 as we get into a couple of years from now.

Importantly, as one of the budget adds, we have decided to continue with the feed study on the Cosmo project, in the Kenai, Peninsula area. That study is underway and we anticipate the drilling of at least one well in 2009 as we get closer, an inch closer to the idea of sanctioning a project there next year. And, ultimately, we are excited to say Alaska is now becoming a growth asset for the company.

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

Rich Dealy

Great. Thanks, Tim, and good morning. As Scott mentioned, net income for the quarter was $159 million or $1.32 per diluted share. Included in that are the items noted on slide 22 here. We did have our Alaskan Petroleum Products Tax Credit that we did receive from the state that increased earnings for about $4 million after tax, or $0.03.

Also for the first time, we have minority interest as a deduction to net income for the quarter of about $5 million. This is associated with the public ownership in the MLP that we formed back in May, Pioneer Southwest Energy, and so that reduced earnings by about $0.04.

As you can see in the box of the bottom, the company had a very, very good quarter with everything. Actual results coming in either at the midpoint or positive end of guidance, other than production taxes, which were above the guidance but that’s production costs, rather. That’s primarily due to production taxes which were higher than anticipated because of higher than expected commodity prices when we originally gave out guidance back in May.

Turning to slide 23 where we talk about realized prices. As you can see in the green bars there, oil realizations were about $90 per barrel, up 16% from the first quarter. NGL prices were up about 4% relative to the first quarter, and obviously, didn’t increase relative to oil prices as much; just principally the result of historically receiving about 55% to 60% of NYMEX oil prices.

In the second quarter, we only realized about 45% of the average NYMEX price for the quarter, primarily due to ethane and propane, which make up the majority of the NGL stream being relatively flat from a pricing standpoint during the quarter, really due to excess supply that existed in the market during the quarter.

Gas prices were up 13% for the quarter to $8.73 on a realized basis, just owning to the run-up that we saw in gas prices during that time period. At the bottom, you can see what our hedge impact, how that impacted these prices for the quarters. Particularly of note is the oil impact. Obviously, as we have talked about in the past, we have a large volume of legacy hedges that run off at the end of this year. So, we do expect as we move into 2009 that our oil price realizations will improve substantially.

Turning to slide 24 on production costs. Production costs per BOE were $13.93. As I talked about earlier, the only main reason for the increase is production taxes, which is a positive from the standpoint they received higher prices for the commodities we were selling. Pleased with base LOE being relatively flat, but I will talk a little bit more on that here on the next slide.

Turning to slide 25 where we talk about third quarter guidance. Daily production expected to average 114,000 to 119,000 BOEs per day. Production costs are expected to be $13.50 per $14.50 per BOE. This is up slightly from the second quarter guidance, generally due to inflation that we are seeing and field costs related to service costs, electricity costs and fuel costs.

Exploration and abandonments, $40 million to $70 million range. This is primarily related to our continued activity in the Edwards Trend in Tunisia, whereas Tim mentioned, we are drilling a number of new prospects this quarter. DD&A expected to be $10.75 to $11.75 per BOE. G&A at $35 million to $39 million. Interest expense at $36 million to $40 million. Minority interest, which is a new item that we have added to the forecast which is comprised principally of the public's ownership in Pioneer Southwest, is expected to be $8 million to $10 million of expense for the quarter. And then cash taxes at $30 million to $40 million, virtually all related to Tunisia as we continue to ramp-up our production there. Our effective tax rate is expected to be 40% to 50% for the quarter.

Turning to slide 26, we show our 2008 estimated discretionary cash flow at $1.5 billion that Scott talked about. This chart allows you to look at what your forecast is for the rest of the year for NYMEX oil and NYMEX gas prices and see the sensitivity to our DCF that those prices may have. Obviously, as we get more and more months of actual results this becomes less and less sensitive.

Turning to slide 27 where we look at 2009. This just gives you some support to back up the $2.2 billion of cash flow we are predicting for 2009. Obviously, about a 50% increase over the levels of 2008, and this is driven mainly by higher commodity prices, but as the legacy hedges roll off, we are realizing a lot more cash flow on those volumes as well as -- and more importantly, that our production continues to grow as we move into 2009.

Turning to slide 28, we have provided a substantial list of supplemental information for your review to help with your modeling and review of the quarter. The hedge position, I will point out that we would like you to take a look at those slides. We have added about 5000 barrels per day oil callers for 2009 and 2010 at 100 by 190. We've also added 2000 barrels per day in 2011 for Pioneer Southwest at 115 by 170. Obviously we own 70% of that entity so it is a hedge for us as well.

Prior to opening up the call for questions, I did want to give you a brief update on our press release that we issued last week related to the SemGroup bankruptcy. As we disclosed in the press release, our pre-petition claims totaled about $30 million associated with condensate from our West Panhandle field that we sell to a subsidiary of SemGroup. We have continued to deliver condensate to SemGroup since the pre-petition date, while we work to get alternate delivery arrangements in place. We have also been working with our bankruptcy counsel to understand SemGroup's future plans, and to get a better understanding of how we will be treated as a critical supplier of SemGroup. It's still very early to predict how that will all turn out and what the ultimate amount and timing of when we will get paid, but we are continuing to closely monitor the bankruptcy proceedings. And we would anticipate having a better understanding of the ultimate outcome here in the next few weeks or months. I think, suffice it to say, we currently do not expect that the ultimate outcome will be material to the Company's liquidity or financial position at this point in time.

So, with that we would like to open up the call for questions.

Question-and-Answer Session

Operator

Thank you very much, sir. (Operator Instructions). We will take the first question from Michael Jacobs of Tudor, Pickering, Holt.

Scott Sheffield

Hey Michael, how are you doing?

Michael Jacobs - Tudor, Pickering, Holt

Well. 0Of the $300 million in higher CapEx, can you give us an idea of how much of the increase is related to more wells versus higher costs?

Scott Sheffield

The three categories we gave you split equally about a third, third, third.

Michael Jacobs - Tudor, Pickering, Holt

Okay. And as we look at trying to get a better understanding of reserve bookings on the Spraberry. The 50 un-booked locations that you have drilled to-date, how many offsets are you planning on booking?

Scott Sheffield

That's going to be -- that's done quarterly as we drill those locations, so we're still targeting $15 to $20 refining costs as a Company, corporately, for the year. So, obviously, depending on when we get approval for the down spacing we will have more flexibility. That just depends if we get it done late this year or early next year.

Michael Jacobs - Tudor, Pickering, Holt

Okay. One last question. As we think about kind of total potential for the Spraberry, can you give us an idea of how meaningful the horizontal stimulation and shale interval projects could be in the context of your three main initiatives to capture a billion barrels?

Scott Sheffield

It is only started over the last three months. So three months of history, as a reservoir engineer you need a lot more history, a lot more time. We are encouraged about the early results.

Just to remind everybody, this field has been producing for 60 years, so you're not going into virgin reservoir pressure. So, I think, obviously, we are seeing that there is more pay in the Spraberry Trend area. It has probably been feeding from the source rock, the shale up into the sands, which we have been completing for years and years. But we think, at the end of the day, we can get more reserves per dollar invested is the key, and that's what we are working on as we do the horizontal fracs and also the shale testing.

Michael Jacobs - Tudor, Pickering, Holt

Great. Thank you.

Operator

We will move on to Gil Yang.

Gil Yang - Citigroup

Hi.

Scott Sheffield

Hi, Gil.

Gil Yang - Citigroup

Can you talk a little bit about what regions, what basins are seeing most inflation or is it pretty evenly spread around?

Scott Sheffield

I would say anything related to steel. With iron ore rising 75% just in the last three months. Anything associated with steel so that's tubulars, pumping units, anything else, tankage steel cost has sky-rocketed over the last three months.

Secondly, if you recall, pumping services had discounts, significant discounts going into '08. We actually saw a drop in our [ANVs] in several areas. They recaptured some of those discounts. Not all of them, but they are coming up. So that's primarily throughout.

Now Raton basin with us is insulated, primarily due to the fact that we have, from the standpoint of -- not from steel - but from the standpoint of other services because we have our own equipment there. But we pretty much have seen it throughout, Gil.

Gil Yang - Citigroup

Okay. In your updated commentary about the returns, Spraberry dropped off a little bit. The other areas went up maybe because of higher gas prices that you used in your modeling. But do you have any view that maybe you're trying to grow too quickly in the Spraberry and maybe you should slowdown activity level a little bit?

Scott Sheffield

It's important to -- the model is to grow as high as you can but create significant excess cash flow. So we are always trying to pick the ideal growth rate but at the same time generate excess cash flow. We don't believe in a model where you overspend cash flow by 30%, 40% just to grow higher rates. So we are trying to pick the ideal growth rate and be consistent at it over the next several years. So Spraberry, the 20% growth rate that we are showing over the last 12 months, if you look at the next four years, we are targeting 15%. So the acquisition that we had last year helped that number. So we are still targeting, basically, 15% with no acquisitions long-term. So that's been our stated public number for over a year.

Gil Yang - Citigroup

Finally, can you talk a little bit about the shale opportunity in Spraberry. How much of this -- it sounds like the shale is almost 650 feet thick where you drilled it. Is that the thickest spot and how much does it vary? And do you think the oil content in places -- how uniform is that throughout the basin? Does it underline all your sand acreage or is it spottier?

Scott Sheffield

If you recall, we have only taken one core and, to our knowledge, we don't know of any other operators that has cored something besides the sand. There are thousands of cores in the last 60 years in the Spraberry but it is all isolated over about 200, 250 feet of sand. So to my knowledge, this is the first core that's been taken, to our knowledge, of potential shale zones.

There is another 1400 feet that we didn't core. So we used open hole logs to identify the first 650 feet. And so, Tim mentioned, we are going to take a lot of cores throughout the entire area. It's 150 miles north to south, 75 miles east to west. So it is a big area. We are going to spend a lot more time and effort on cores. Obviously, it is going to be in some form or fashion throughout the Spraberry because it is basically the source rock that has developed several billion barrels of oil feeding into the sand. So that's going to take time to answer the question.

Gil Yang - Citigroup

Am I wrong, but isn't the shale sandwiched between the upper and lower Spraberry sands?

Scott Sheffield

There is shale below the lower Spraberry, and there's shale between the upper and lower, so it is both. So it is both, yeah.

Gil Yang - Citigroup

Which shale did you just test into?

Scott Sheffield

We tested the stuff closest to the upper and closest to the lower.

Gil Yang - Citigroup

Okay. Alright. Thank you.

Operator

We will next move on to Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs

Good morning.

Scott Sheffield

Hi, Brian.

Brian Singer - Goldman Sachs

Somewhat following up on Gil's question. When you look at the various opportunities throughout the US and throughout the world that you're investing in, how if at all would you adjust depending on -- adjust your capital spending depending on movements in oil, natural gas -- North American natural gas, and international gas prices? I guess, what flexibility is there when you think about Tunisia, Spraberry, onshore US gas, to switch your capital program if you see opportunities, or if there are dislocations between oil, gas and international gas prices?

Scott Sheffield

Rich didn't talk about it, but if you go back in the back, on one page, the reason Tim talked about Tunisia gas is we got paid $15 second quarter. Obviously, with LNG going into southern Europe somewhere between $15 and $18 and getting paid $15 for Tunisia's gas, it is a very important project. So Tunisia, even with the gas investment, is still the highest return project in the Company.

Second, if you look at, on a DROI, oil is very important, anything oil related. So Spraberry is a very important piece of that. So we have flexibility on the gas side. So, I guess, there are two schools of thought where gas is going. I have been surprised gas has come down so quick when the rest of the world primarily is getting $15 plus for either LNG or some form of gas. So, it depends on what happens with US natural gas prices going into 2009. We do have flexibility to move around our CapEx, primarily in Barnett, Raton and the Edwards Play if we see returns erode in those three areas due to low natural gas prices.

Brian Singer - Goldman Sachs

I guess any numbers behind that? And if gas prices, for example, stay at these levels or world oil prices stay, let's say, above $120, what would gas prices does make sense to maybe reduce activity in some of the North American gas plays and shift into oil and international gas?

Scott Sheffield

I would say $8 gas is going to be very tough returns, versus $120 crude. So you'll see us put more money in the Spraberry Trend areas as we have indicated and probably do some cutback on natural gas. $8 and below.

Brian Singer - Goldman Sachs

Great. Thank you.

Scott Sheffield

That's $8 NYMEX minus your $1.40 differential, so you're netting $6.50 across the Company.

Brian Singer - Goldman Sachs

Thanks, Scott.

Operator

We will next move on to [Scott Wilmeth] of Simmons & Company.

Scott Wilmeth - Simmons and Company

Hi, guys. Just looking at the free cash flow you guys are going to generate in 2009. Can you guys give us a rank order of your plans for that free cash flow?

Scott Sheffield

Yes. Obviously, the first portion is increasing certain areas we have talked about already based on where we see commodity prices, but that's primarily in the Spraberry, in the Barnett Shale, and some in Raton. Second, would be some small acquisitions in those areas. Third, share repurchases. And fourth, debt reduction.

Scott Wilmeth - Simmons and Company

Then moving to the Pierre. With the horizontals planned for Q3, will those be targeting Kp1 or will you guys be able to get Kp2 and 3 as well?

Scott Sheffield

No, just Kp1.

Scott Wilmeth - Simmons and Company

What are your estimated costs for those?

Tim Dove

$1.5 million.

Scott Sheffield

Total? Tim said $1.5 million.

Scott Wilmeth - Simmons and Company

Okay. And then when we look at down-spacing to 20-acre in the Spraberry, activity for 2009 with the 40 wells, is that contingent upon the Railroad Commission approval?

Scott Sheffield

No, it’s not. We have about 300 locations that we can get rule 38s, called density for exceptions. We can drill about 300 wells before we have to get Commission approval.

Scott Wilmeth - Simmons and Company

What is the confidence of receiving approval?

Scott Sheffield

Going back for the ones over the last 30 years, it went from 160s to 80s to 40s. We received approval. It’s an easy case to present. It is a question whether it is protested or not. Protested will take about six months, almost up to six months. Unprotested will take three months.

Scott Wilmeth - Simmons and Company

Okay.

Scott Sheffield

So we have an excellent case. We've drilled over 1000 wells on 40-acre spacing and we are still getting 80% recovery of 80-acre well of new reserves. So we are very confident, especially based on the shale testing that Tim talked about, the horizontal frac, that there was a lot of oil in place and you need 20 acres to develop Spraberry Trend area.

Scott Wilmeth - Simmons and Company

Great. Thanks. That's all I had.

Operator

We will take the next question from Jon Wolff of Credit Suisse.

Jon Wolff - Credit Suisse

Thanks. Good morning.

Scott Sheffield

Hi, Jon.

Jon Wolff - Credit Suisse

How are you doing? Got to some of mine, but in terms of the Pierre, would it be possible to design a horizontal completion that could get to more than just the Kp1?

Scott Sheffield

The initial thought, if the Kp1 turns out to be pretty decent on the horizontal, then we will possibly let it produce for a while and maybe go back up and open the Kp2 and 3. The team has talked about more of a slant angle into the Kp1, 2 and 3. I don't know whether or not we will try that or not, but the focus is on Kp1 and then going back later an opening up Kp2 and 3. We might be able to do a high angle, Jon. I don't know.

Jon Wolff - Credit Suisse

In terms of what you've seen in the cores in Kp2 and KP3, it sounds like there is enough gas in place. It is a pressure issue? What are the issues there?

Scott Sheffield

The ToC is lower, as I think we initially talked about, but -- and we have only had a couple of wells that we have tested the Kp2 and 3. So depends on if it holds its 20% to 30% sustained rate. So based on that, we don't know if it is worthwhile putting a horizontal well in there. But if we have pretty good success in Kp1, we could end up putting one in the Kp2 or KP3 at some point Jon.

Tim Dove

Jon, one thing you're dealing with is you've got a higher clay content in the Kp2 and 3. So it's just also a matter of the effectiveness of the frac in those sections as compared to the Kp1 where you have a lower clay content.

Jon Wolff - Credit Suisse

Okay. So it sounds like the horizontals are about twice the cost?

Scott Sheffield

Something like that.

Jon Wolff - Credit Suisse

You think? Something like that. Are you looking for at least two time reserves or is it more to do with the IP rates?

Scott Sheffield

It's more -- IP rate is important to pay out, but reserves are the key. We've got to get a lot more reserves. It's economical today just to open up the zones. If you attribute all of the costs to Kp1, to drill the well which is very economical, and just look at the $300,000 investment to get a 30% increase in sustained production, it is worthwhile. It is not a huge barn burner, but it is still a worthwhile investment.

Jon Wolff - Credit Suisse

Got it. Last one. Update on Cosmopolitan?

Scott Sheffield

Basically just moving forward on our study. In the budget next year, we are looking at basically drilling a couple horizontal wells and frac'ing. We have not done any frac'ing. We tested both these wells at about 500 barrels a day each and we are looking at a frac job to continue to improve productivity, but that's in the proposed CapEx of 2009 which we won't approve until toward the end of the year.

Jon Wolff - Credit Suisse

Rich made a comment about NGL markets being a little over supplied in the second quarter. Do you have any updated thoughts on that thinking?

Scott Sheffield

During the month of July, it is back in the 50% range, but all the reports I've read -- with crude coming back about $30, NGLs have not fallen proportionately. But with all the condensate, NGLs are being driven by the increase in rig activity. Obviously in some of these shale plays too that are a little bit richer in condensate, it is putting extra ethane and propane into the marketplace. So I think we've got to wait until we see what happens coming winter and see what happens, especially on the butane and propane markets. I'm guessing it may come back to 50%, 55%.

Jon Wolff - Credit Suisse

Okay.

Rich Dealy

Jon, if you look at the forward curve mark, which I'm sure you have, it's still in that 45% to 50% range, after you get out a year or so.

Jon Wolff - Credit Suisse

Okay. Thank you.

Operator

We will next move to Leo Mariani with RBC.

Leo Mariani - RBC

Question on your Spraberry shale here. That vertical wall you had on production for four months, you said doing 40-barrels a day now. Did that come on at a higher rate and did you guys frac that well and maybe if you did, could you talk a little bit about the frac you used?

Scott Sheffield

That well basically came on in the neighborhood -- depends which day you are looking at, Leo. You could have 120 days to select from. But it produced on some of the days as much as 70 to 80 barrels a day when it first came on production for the first couple of months. The frac we put on there was your traditional Spraberry frac.

Leo Mariani - RBC

Got you. And I guess, your program, throughout the year obviously, you've got a well right now, you're looking it sounds like to commingle with the sands and the shale. Are you guys going to try to establish what the communication is between the shale and the sands with some of these wells you're going to drill going forward?

Scott Sheffield

We will be doing an evaluation of the petro-chemistry involved here associated with where the production is coming from using isotope technology. And what we are really doing is perfing and completing and frac'ing the wells in both what we could call the traditional sand-oriented pay intervals, as well as in these newly defined silty shale intervals as well. And so, we hopefully will have a good idea after drilling several like this to get an idea of exactly where we are getting incremental production, from which zone and what rate.

Leo Mariani - RBC

Okay. Jumping over to the Pierre, you mentioned a couple of horizontal wells. Have you started drilling those at this point, and when do you anticipate having some results on those?

Scott Sheffield

We have already started drilling the first well, as I mentioned earlier when I was discussing these. I would anticipate these wells are four weeks, door-to-door each. So by the time we get through eight weeks we will probably have them both drilled, and that would mean, probably, about this time next quarter we will be talking about the results.

Leo Mariani - RBC

Jumping over to Tunisia here, real quick. You mentioned pretty recent exploratory successes. Could you give us more color on what you saw out there and if you tested those wells and what kind of rates you saw?

Scott Sheffield

We drilled three wells. One was on Pioneer acreage. Two was on Adam BEK acreage by NI. One well we mentioned in Tim's report is the 17 million a day and 1000 barrels a day in condensate.

We think as you move south into BEK, we will find it will become more gassy and condensate. Moembe, we didn't talk about it, but they had two other not as good as this recent well. This recent well, they just press released about two weeks, it tested in the -- 120 million a day, over 3000 barrels in condensate. But they had two other wells, of probably about -- right adjacent, a few hundred feet away from our BEK block that has been some of our slides over the last 12 months, so they made three significant gas discoveries. Up in Jenein Nord we had an LSL, and then Adam had a well -- I think they tested combined rates about 4000 barrels a day between both wells.

Leo Mariani - RBC

Okay. Could you give us any type of preliminary work at what your 2009 exploration program could look like in Tunisia. You mentioned finishing a lot of seismic work this year in defining prospects. Would we expect to see a larger number of exploration wells?

Scott Sheffield

Not until we feel like it is worthwhile putting in a second rig. So, the key to more spending will be increasing spending a little bit with the gas project, but until we decide on a second rig we don't see much increase in Tunisia going into 2009.

Leo Mariani - RBC

Okay. Thanks for your time.

Scott Sheffield

Thank you.

Operator

We will next move on to Wachovia's David Tameron.

David Tameron - Wachovia

Nice outlook on the forward guidance.

Scott Sheffield

Thanks, Dave.

David Tameron - Wachovia

Can you -- In your slide you talk about Raton growing 10% to 15% through now 2011, and you said that reflects the Pierre Shale contribution?

Scott Sheffield

Yes.

David Tameron - Wachovia

Maybe you mentioned the number, I missed it. Can you talk about what type of contribution you are expecting over the next couple of years?

Scott Sheffield

Right now, 10 to 12 wells is contributing about $3 million a day settled rate, so we are going to be drilling 50 wells. So it's going to be small up until you get into the third, fourth and fifth year. Also, we are tempering the 10% to 15% with our expansion in 2011 of additional capacity, there's about 50 million a day left in the current system capacity, primarily going to the mid-continent Texas panhandle, which is where we get our differentials.

David Tameron - Wachovia

Okay.

Scott Sheffield

So we have that capacity, so we see that kind of growth. So even if Pierre comes in let's say significantly better with horizontal success, we are going to be limited until 2011. More in the 10% range.

David Tameron - Wachovia

Okay. All right. And everything else has been answered. Just wanted to ask one more question. And I don't want to send over the edge here, but could you talk about pending Colorado legislation and what impact, if any that could have on your position in the Raton.

Scott Sheffield

So far our people, with the support of the community, have done an excellent job of getting the counties where we do most of the drilling excluded from most of the potential legislation that we see. So that's the most positive thing I can say. And it is a combination of working with the community, getting the support of the community. So we have had some potential exclusions that we see coming. So the decision will be made in the next two months. But one of the negative ones we just don't see affecting us and that's the no winter drilling, for instance.

David Tameron - Wachovia

Okay.

Scott Sheffield

For three or four-month period, we just don't see that with the support of the community that we've had, and the outcry. So we expect to be excluded.

David Tameron - Wachovia

Alright.

Scott Sheffield

Do you have anything else on that?

Tim Dove

I think we made a lot of good inroads in terms of trying to mitigate some of the attempts by the administration to really tighten down water issues, as an example. Out here, we produce a large amount of potable water and the new restrictions would have had us to re-inject all this water. Well that doesn't make any sense considering all the ranchers and farmers want that water for livestock and other purposes. We have been able to mitigate some of the real negative issues toward the benefit of Las Animas County, where we do most of our operations.

David Tameron - Wachovia

Alright. Thanks.

Scott Sheffield

Any last questions before we close?

Operator

We do have a question from Rehan Rashid from Friedman, Billings, Ramsey.

Rehan Rashid - Friedman, Billings, Ramsey

Hello, Scott.

Scott Sheffield

Rehan, how are you doing?

Rehan Rashid - Friedman, Billings, Ramsey

Good. On the Spraberry horizontal, any initial thoughts as to why you are not seeing the hyperbolic decline that you might have expected?

Scott Sheffield

Obviously we are contacting a lot more pay. So it shows you that there -- it is like drilling a series of several wells. What's encouraging is that -- when you go back and look at our horizontal wells, 20% of them did very well, 80% were poor. And Tim mentioned, we did not stimulate any of those wells. And so that's why we shut down the program about 15, 12 years ago. So we are going back in there and fracing and it just shows you there is a lot more oil and gas in these areas and some of it could be coming from the shale zones on both sides of it. So we are just exposing with a frac job your fracing -- what's encouraging is we only went out 700 to 1000 feet. I would -- what I would like to see happen is drill some horizontals, go out 2,000, 2,500 feet and do the Packers Plus technology and see what kind of rates we get. That's what we are planning. The question is, do you put it in the sands? Do you put it in the shales? Or do you do both? That's what we are trying to decide on. As Tim mentioned, we are going to drill five of them here early next year.

Rehan Rashid - Friedman, Billings, Ramsey

And I read in some literature somewhere that Spraberry has been drilled up so extensively from a vertical standpoint that the whole field is in a vacuum. Is that correct, first of all, and if so, would this have an effect on how you or what portion of the overall field could be a prospective for horizontal?

Scott Sheffield

Yeah. A typical, as you see in the back, comes 40, 50 barrels a day and drops off very fast, very significantly. You get a payout of about three years. And what's critical is get that flush production sold at a good return, good high oil price. And it's got very rich gas. And so the -- all wells have to be pumped. Now some of these Wolfberry wells, which is virgin reservoir pressure, going deeper in the Wolfcamp, those wells flow. Reservoir pressure is down about 2000psi. It's not been on a vacuum. Our West Panhandle field has been producing since 1920, 1910, it is on a vacuum.

Tim Dove

And Hugoton as well.

Scott Sheffield

And Hugoton. So it's got a long way to go, the Spraberry Trend area. If you look at our slides that we have used in the past, it's the largest onshore US top 10 fields that's still growing. So exclude the deep water projects, it's the largest, it's still growing and been growing consistently since 1950s.

Rehan Rashid - Friedman, Billings, Ramsey

Going to the Rockies for one quick second. You talked about moving or wanting to move the gas west. From a logistic's standpoint, what pipeline? Any thoughts on that front?

Scott Sheffield

We are in the El Paso line commitment to Malin, Oregon. So right now, that improves the differential significantly if you start looking at the prices received at Malin, Oregon. But that won't happen until 2011.

Rehan Rashid - Friedman, Billings, Ramsey

Okay.

Scott Sheffield

Thank you.

Operator

Final question will come from [Chithra Sandara] of Cardinal Capital.

Chitha Sandara - Cardinal Capital

Thank you and congratulations. My question was on hedging. In this current environment with the level of volatility in energy markets, I guess my first question is, what would lead you all to hedge more of your '09 and '10 oil production? And if you did want to do more, do you feel like it is a market in which you could get a bit?

Scott Sheffield

We don't see a lot of supply come in the market. I still see Asia growing in demand significantly. China has got a long way to go. So I don't see additional supply. The crude price probably ran up too quick, recently. It would be nice to see it settle down between $100 and $120, but there will be extreme volatility to the upside. Obviously, with political events in the world - Venezuela, Iran, Pakistan. So our philosophy is we continue to see spikes. We will continue to lay on -- layer on more of these costs as callers. If we see huge spikes, we may do some swaps.

Chitha Sandara - Cardinal Capital

Okay. Very good. Thank you so much.

Scott Sheffield

Thank you.

Operator

And there appear to be no further questions at this time. I will turn the conference back to you, gentlemen.

Scott Sheffield

I want to thank everybody for taking the time and we look forward to seeing everybody on the next quarter, third quarter. Good day. Thank you.

Operator

That does conclude this conference call. Thank you all for joining us and have a wonderful day.

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