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Pioneer Natural Resources Company (NYSE:PXD)

Q1 2008 Earnings Call

May 7, 2008 10:00 am ET

Executives

Scott D. Sheffield – Chairman and Chief Executive Officer

Timothy L. Dove – President and Chief Operating Officer

Richard P. Dealy – Executive Vice President and Chief Financial Officer

Frank E. Hopkins – Vice President of Investor Relations

Analysts

Gil Yang – Citigroup

Brian Singer – Goldman Sachs

Nicholas Pope - JP Morgan

Robert Lynd – Simmons & Company International

Leo Mariani – RBC Capital Markets Corporation

David Tameron – Wachovia Capital Markets, Llc

Rehan Rashid – Friedman, Billings, Ramsey

Joe Magner - Tristone Capital

Operator

Welcome to Pioneer Natural Resources First Quarter Conference Call. Today’s conference is being recorded. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer, Jim 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. At the website select Investor, then select Investor Presentation.

The company’s comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities and 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 and 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, Mr. Frank Hopkins.

Frank E. Hopkins

Good day everyone and thank you for joining us. I am going to briefly review the agenda for today’s call. Scott is going to be the first speaker. He will review the financial and operating highlights for the first quarter of 2008, which was another strong quarter for Pioneer. He will then comment on the company’s outlook for continuing production and cash flow growth, as well as our increasing resource potential and net asset value. After Scott concludes his remarks, Tim is going to review the performance of our key assets in the first quarter and expectations for the remainder of the year. Rich will then cover the financial highlights for the first quarter and provide earnings guidance for the second quarter. After that we will open up the call for your questions.

Before turning the call over to Scott, you may have read yesterday that Pioneer Southwest Energy Partners announced a closing of its initial public offering. Please be aware that the rules of the SEC continue to limit the information we can disclose about this master limited partnership until the end of this month. Therefore, we are unfortunately restricted as to what we can say about future plans and expectations for the MLP on this call and the meetings with investors and analysts over the remainder of May.

With that, I will turn the call over to Scott.

Scott D. Sheffield

Thanks, Frank. Good morning, and again, I am going to start out on Slide 3.

As Frank said, we had another great quarter. Reported first quarter net income of $130 million, or about $1.09 per share. Our production grew to 110 MBOEPD, a very, very high, actually over guidance that we gave last quarter. We are up 24% versus 12 months ago, first quarter of 2007.

Secondly, three of our big assets, Spraberry, Raton, and Edwards are up 31% over that same time period.

We are continuing to believe in our production per share of growth of 14% CAGR through 2011, especially starting out with a strong first quarter.

Discretionary cash flow is up 65% versus first quarter of 2007. We have also, with the recent price movements over the last several months and also with our Spraberry announcement and our Pierre Shale announcement, we’ve updated our net asset value. These are after-tax numbers discounted at 10%. At $85 flat and $8.50 flat we are at $109 per share and at $100 all flat and $10 gas flat we are at $153. So it’s important that we’re continuing to add net asset value each year with our program.

Also, we did close yesterday, the $163 million in proceeds, our transaction with Pioneer Southwest Energy Partners.

Slide 4, Operational Highlights. Again, we made a major announcement, thing we’ve been working on for a little over a year in regard to the Spraberry field that represents over half the company. It’s another 1 BBOE resource. We started drilling on 20 acres spacing infield drilling earlier this year. Very positive results. Tim will talk more about it.

And then secondly, we probably did this before our time, but we went out and drilled several horizontal wells before the stimulation technology was there, about 10-15 years ago. We’re going back in, getting very positive results about going back in and using the oscillation-factors-type technology to frac these wells and getting excellent results.

We also announced the Pierre Shale with over 2 TCF resource potential, continuing to see very positive results there.

We have already hit our exit rate in Edwards, 2008 exit rate. Continue to see very, very positive results with our wells.

Also, we had a great quarter with regard to 3 new Silurian wells in Tunisia, which will continue to add to our production.

And then what is very interesting, too, with [inaudible] in the Ghadames Basin, one of the most prolific basins in North Africa, our geophysicists and our geologists are starting to work the site much harder, but we’ve had two nice discoveries tested, about 3,500 BBOE in the Ordovician and the TAGI formation. Once is deeper than the Silurian and one is much shallower. So also very important adding other potential formations in our Tunisia operations.

As a result of both the success in Edwards, and also Tunisia, we are continuing to expand our facilities in both of those areas significantly.

Also, development drilling got underway in Oooguruk, with first sales expected late summer.

Slide 5, again shows how consistent production growth with our strategy, began about 2 years ago. We’re seeing, obviously, a very strong quarter, it’s very consistent production growth, and we will continue to see that with all of our operations. Again, up 24% over the last 12 months.

Slide 6, again, just in emphasis. Most people have seen this slide. We continue to believe in our 14% per share CAGR. Obviously we think we will do better than that based on this first quarter and how everything is doing between now and 2011. This assumes no additional share repurchases over the next 4 years.

Slide 7, again, just to re-emphasize the strong returns that have various price jacks, both at $70 where we test everything at, $70 and $7 flat, on high case $95 and $9. Obviously we’re seeing much better returns today but we’re still being conservative in where we look at allocating capital. Still very, very strong returns in all of our key assets, as shown here.

Slide 8, just a reminder to people that our legacy hedges are rolling off, beginning at the end of year, about 6-7 months left. They continue to roll off, adding about $600 million of pre-tax cash flow, accumulative, by the end of 2012.

Slide 9, again, we’re targeting 20% growth and 20% compounded growth rate after-tax cash flow. I think that the big focus right now, and Rich, when he goes over his financial section, is that we’re close to $1.4 billion cash flow in 2008 and we are up to $2.2 billion right now, based on current commodity prices in the strip for 2009. So, it’s over a 50% increase from 2008 and after-tax cash flow for Pioneer going into 2009.

Slide 10, again, just an update of the reserves and how we use this to come up with our net asset value. Again, the big increase is primarily in Spraberry, Raton, with the Pierre Shale, and it’s work over the last 12-18 months. So again, we added significant resource potential. We’re up to 2.8 BBOE.

Slide 11. A little bit more detail on our net asset value. What makes up the $109, the $153. Proved, the $85 and $8.50 case is $53 and the $110 case proved at $72. So still a lot of running room, we think it’s important to focus obviously the allocation of capital on continuing to develop our probables in each of those categories to realize the net asset value, the upper limit at those prices. This is all at 10% after-tax.

Slide 12. As Frank said, we can’t say a lot about Pioneer Southwest Energy Partners but we had a very, very successful offering. The MLP was obviously formed to acquire oil and gas assets in Texas, primarily the Spraberry Trend area. The primary focus will be PXD’s core operating areas. The primary reason for the MLP is really to allow PXD to more effectively pursue acquisitions through joint bidding with the MLP. The MLP will buy the proved developed reserves on both owned acquisitions and PXD will buy the undeveloped resource potential.

Again, we had a very successful offering. Net proceeds of $163 million. Pioneer will own 68% of the partnership and the value of our current units is a little over $400 million, $410 million.

On Slide 13, again, on summary, we are on track to deliver our target of 14+% CAGR through 2011. We have a tremendous low-risk inventory, support that repeatable, consistent production growth over the next several years, again targeting growth and 20% after-tax cash flow CAGR. Again from 2008 to 2009 we will see a 50% increase in cash flow, from about $1.4 billion to about $2.2 billion. And then earnings are expected to double in 2008, triple in 2009, as compared to 2007. We think it is important to generate free cash flow, as we will in 2008 and beyond. We have a great resource base, and again, we’re still trading well below our net asset value.

Let me turn it over to Tim.

Timothy L. Dove

Thank you, Scott.

And as Scott has already alluded to, with an excellent first quarter, we can say that we are, really from an operational standpoint, hitting on all cylinders. First, though, I thought I would take a few minutes to provide some color on the two major resource play initiatives that Scott had alluded to and we have been discussing. I will touch on those prior to talking about developments in some of our other core areas.

But first, on Slide 14 is an enumeration of the resource potential in the Spraberry trend area. One of our major objectives in the company, of course, is to begin the process of capturing more of the enormous resource potential that this trend has. And realizing it is the fifth largest oil field in the United States, with over 30 billion barrels of oil in place, and it is one of the largest onshore fields, in fact, the only one that has been growing in the last five years.

We know if we can increase the recovery rates, we can add substantially to the company’s resource base. We have essentially 50% of the field, on most metrics. About 869,000 gross acres, about 75% of that is held by production. So what we’re really dealing with here is a big field that’s getting bigger and doing some good things for the company.

We have several initiatives ongoing, one of which is simply to complete our 40-acre program. We believe that will yield approximately a 12%-13% recovery rate in our areas of operation. And as to the unbooked potential on 40-acre spacing, we would say that’s approximately 200 million BOE net to Pioneer.

One of our major new initiatives, of course, though, is to plan to further downspace the field to a 20-acre drilling. If you simply do the calculations across the acreage base you would say we could calculate some 21,000 potential drilling locations on 20-acre spacing. We have high-graded that to about 9,500 drilling locations based on optimizing locations based on nearby 40 acre locations. And that would generate about 500 million barrels of additional resource potential net to Pioneer.

And toward that end, we are completing several wells. In the first quarter we drilled about four and further to that end we will drill about 20 or 25 20-acre wells this year. The returns we see as to how those wells are doing are excellent. In fact, the first four wells are essentially tracking what 40-acre well type curves look like. Overall, from a resource base standpoint, we are calculating our potential here based on about an 80% recovery of a 20-acre well as compared to a 40-acre well.

And what that can do in the areas where we downspace is increase our recovery rates from that 12%-13% to say, another 6% or so, to 18%-19%.

In addition, we are actively working on implementing a large waterflood, beginning next year. That will be one of many waterfloods that have actually been undertaken in the field. There have been about ten waterfloods put in place in the fields since the 1960s. We think about 40% of our acreage would be applicable for water flooding and the history of the prior floods shows that for every barrel of primary recovery in the field we get about an additional 0.5 barrels in the case of the waterflood.

So the resource potential is enormous on that basis and we believe that in the areas where we waterflood we can actually increase recovery rates and additional 9%, which would be, if you calculate it across that approximately 40% of the acreage, about 300 million barrels. So, it’s pretty easy to see that we have 1 billion barrels of resource potential roughly, in this field that is currently unproved. And so one of the major objectives of the company, of course, is to unleash that large resource potential as we move forward.

Scott alluded to the fact we have also started to employ some of the more recent technology applications when it comes to stimulating horizontal wells. In fact, we’ve already planned to frac five wells this year and have already fraced one, have two underway. The results look excellent. And I think there will be applicability in certain areas of the field, especially when circus issues will call for horizontal drilling. And so this is something we are actively pursing.

We will report more after we have a little bit more historical data on well performance. But so far, so good, in terms of the kind of impact that horizontal frac technology can add.

Then turning to Slide 15. This is a little more oriented towards our drilling campaigns. We are drilling about 350 wells this year. You can see in the center part of the slide at the bottom that production increased, quarter to quarter that is, first quarter 2007 to first quarter 2008, about 21%. So we are in the midst of a strong production growth campaign in this field. And we believe that production will grow approximately 15% overall this year, at a minimum.

And I think that the bottom line when it comes to the kind of resource potential that we mentioned earlier, it makes sense to accelerate Spraberry drilling. We will be looking at increasing our drilling activity beginning in 2009. The objective, of course, will be to add rigs at a pace that controls cost increases and doesn’t tax our service providers.

And I think the result of which well be, not only will we be able to produce a CAGR growth rate of 15% in the short term, but only in the long term, through 2011, by ramping up drilling in this field. Taking advantage of that enormous resource potential.

Now turning to Slide 16. This is new as of about a month ago, but it’s not something new in terms of Pioneer in the sense we’ve been working on the Pierre Shale play for about two years. This is, fortunately, sitting directly under our coals in the Raton Basin. So we get a tremendous advantage when it comes to infrastructure and employing our integrated well service model which works so well on coal-bed methane.

We have drilled now several wells. We’ve drilled about ten vertical wells in the play. And, in fact, we have one well that’s now been on production about 17 months and another that’s been on production about 11 months. So we have a significant amount of historical well control in the shale, and in fact, what we’re really dealing with right now so far in terms of data is the lowest of the shales.

If you look at the bottom of Slide 16, you see on the right, the Kp1 270-foot shale at the bottom of the section. That’s been our focus so far and we have seen excellent results and we are at the point where we can say pretty defensively vertical wells, at a minimum, in the Kp1 are economic, generating some 40% IRR based on $8 gas.

Of course, now what we’re trying to do is enhance what this new field can give us and there’s a lot to be said for the fact you have 21 TCF of gas in place. At a minimum we think the resource potential is about 2 TCF. It adds substantially, in fact it doubles our Raton Basin drilling inventory, which is a big positive.

And we are, in fact, starting to build reserves. We built some reserves in the end of 2007, and it will be a significant contributor to reserve bookings at the end of this year and into 2010.

One of the objectives, of course, is to determine whether, on the one hand, horizontal drilling will be able to give us a multiple of a vertical well bore, and also, we’re additionally testing the Kp2 and Kp3 sections. As shown, that’s about 1,100 feet or 1,200 feet of shale, as well. And the early results are very encouraging for that. We’re seeing contribution from those zones and some of these new wells and I believe we will have contributions from Kp2 and Kp3 when it comes to several areas of the field. And that will then contribute to our recovery rates, I think, and will only enhance the economics I mentioned.

So we’re very excited about Pierre. We’re sort of fortunate, needless to say, it sits underneath our existing coal bed, which gives us a lot of traction in terms of having the infrastructure already in place.

Turning to Slide 17. We are drilling about 175 wells this year and 15 of those will be in the Pierre and you can see on that slide that we’ve already drilled about 42 coal bed methane wells and 4 Pierre Shale wells with very good results. We will probably be wrapping up drilling in 2009 and that will lead us to the CAGR growth rate and return of about 10%-15%.

If you look at the green bars in the middle of the slide, you can see our production was up dramatically in the first quarter of 2008 compared to the first quarter of 2007. In fact, it was up about 31%. That is owing to two things. One is, we had the Petrogulf acquisition, which was done in the fourth quarter, in addition to which last year’s first quarter was relatively low due to the heavy snows in Raton. If you calculate what our growth rate is absent those two, it’s still in the 10%-11% range. So Raton continues to produce, and produce well. And it give us confidence in our ability to grow the asset, especially when you combine the coal bed opportunities with Pierre Shale.

And as a result, one of the things we’re doing is we’re adding firm transportation out of the market, in this case, to northern markets. Most of our gas today goes to mid-continent markets.

So the Pierre Shale is really enhancing Raton and it really adds like to what has been a phenomenal asset for Pioneer.

Slide 18. Changing the subject now to a couple of our core areas that are growing dramatically. We start with Edwards. We continue to have a great deal of success in Edwards, as evidenced by the production growth we’ve seen. If you look at the bottom again, in the center of the graph, you see that production is at about 700 million cubic feet a day for the first quarter. That’s up about 65% from the first quarter of 2007, and essentially, as Scott had already mentioned, at our year end exit rate, based on a 25% year-to-year growth rate.

And that’s coming from the fact that we’ve drilled a large number of very strong producing wells in the large fields that were discovered in 2007, excellent rock quality, which has led to really strong rates. 10-18 million cubic feet a day on tests, and the result of which is we have filled up our infrastructure in some areas so one of the major objectives we are doing is to add infrastructure, which means, in this case, amine treatment and gas processing, along this 200 mile trend. We think we’ll add about 20 million cubic feet a day from existing wells that are currently shut in by adding new capacity over the rest of the year. Probably in the neighborhood of 25-50 million cubic feet a day.

We are also completing our 3-D seismic. We have about 60% of a large shoot that’s done, across the trend. And we will be done with that by the end of 2008. Of course, that’s needed in order to properly image the reef trend and understand exactly where these horizontal wells should be drilled and where the best facies is for the drilling of the wells. And you can see, so far we’ve had a great deal of success in doing exactly that, based on how well the production has increased.

Turning to Slide 19. Of course, in Barnett, we’re just starting up our activity. It’s early days for Pioneer in the Barnett but we are cranking up our activity in the sense that we have several wells we’re going to be drilling this year. We have our first rig out in Parker County that has drilled two wells. It’s early days and production is just being tied in but I think these wells are going to come in as anticipated. And we will expect to ramp up a several-rig program as we get into 2009 and then the whole objective is, of course, is we’re starting this from such a low base it can have a nice impact on Pioneer’s growth rate. At current rates it’s about 15 million cubic feet a day and we will be taking that up to 100 or so million cubic feet a day by 2011.

Turning now to Tunisia, another one of our major growth areas. Slide 20. It’s just like Edwards, we’ve had a great deal more success in this key growth area and you can see, as Scott already mentioned, three new Silurian wells having been drilled in the first quarter, successfully. And importantly, a couple of wells that tested the new zones, that Scott referred to, the Ordovician, the TAGI, the TAGI being about a thousand meters above the Akagi and the Ordovician about 600 meters below it. But combined, they test at about 3,500 barrels of oil equivalent per day so this is something that has got us intrigued in terms of a new zone in existing areas, which is something you’re always interested in pursuing. We will probably be evaluating new wells, targeting the new zones.

We are completing large 3-D programs here, too, and not only in Anaguid but in Cherouq. Incidentally, Cherouq, you may see in some of our publications now, is the area that has been designated as the producing concession that was a part of Jenein Nord. So we’ve had several discoveries in Jenein Nord, a part of that has been carved out as a producing concession called Cherouq, and so you will see us now refer to production from Cherouq as one of our key contributors in terms of growth in Tunisia in addition to Adam and Borj El Khadra.

The Cherouq facilities, incidentally, are on schedule. We did start production up in the late part of 2007 but since we have just started up production we haven’t seen a lot of impact yet. In fact, if you look at the green bars at the bottom, our reported sales were essentially equivalent in first quarter 2008 to last year’s first quarter. Our production actually was about 5,000 barrels a day, and of course we can only report the actual sales when they occur, in terms of equating those to production. But overall, we’re seeing an increase in production as we tie in new wells, as infrastructure is put in place.

Today in Cherouq we have about 5,000 barrels a day of gross capacity. Of course, Pioneer has 50% of that. We will have that at about 10,000 barrels a day by the end of this quarter, and 20,000 barrels a day during the fourth quarter. And so what you will see is a ramp up of production. The wells are drilled, they’re ready to be tied in. It’s simply a matter of getting tankage put in place in the field and we’ll see production ramp up. It’ll be very much back-weighted when it comes to 2008 production.

And you can start to see that somewhat in the sense our current production rate is actually 6,500 barrels of oil equivalent per day from our current producing areas, so we’ve seen some of the bump that’s come from starting to fill up the existing facilities capacity, and that will increase as we move through the year. Again, a back-weighted growth for Tunisia, but it will be substantial when we get all that tankage in place.

South Africa, the Sable and gas production continues on the South Coast Gas Projects, Slide 21. Not a lot of news to report here other than to say we’re still anticipating that we will turn around the Sable injection well into a gas producer at the end of 2008 or into early 2009. One of the results of which will be the release of the Sable FPSO, which is processing current crude oil production in the Sable field, and one of the reasons that is significant is because the cost of that facility is significant in the context of oil production on decline and has led to significant increases in LOE that we will then not be subject to when that Sable FPSO is released. But we are getting very strong margins in this production related to the fact that the pricing is set based on Brent crude oil prices.

Slide 22, Alaska. Everything is on target with Alaska. We really are excited about our prospects to begin production as the first independent on the North Slope producing oil. So that will be a red letter day for Pioneer.

Oooguruk drilling is underway, we have drilled our first producer. As a matter of fact, we are drilling our second producing well as we speak and we will have about five or six producing wells on stream by the end of the year, in addition to which this is a waterflood project from day one. We will have several injector drills as well. Of course, it’s about 50/50 producers in injectors when you look at the overall plan of development.

So what we can anticipate then, is we will begin to ramp producing wells available, we need to have enough producing wells for flow assurance. We can only count this as production when it’s sold so we anticipate, actually, first sales will occur at the end of the summer, after maintenance is completed at the onshore facility that’s processing the oil. And net production should be about 3,000-4,000 barrels a day by the end of the year.

At Cosmo things are progressing really more in terms of permitting and the facilities work and we’re planning on drilling an additional well, potentially then with an idea on sanctioning a project there in the middle of next year, let’s say, and first production a couple of years after that.

So that completes my comments and I’ll pass it to Rich for a discussion of the quarterly financials.

Richard P. Dealy

Thanks, Tim. And good morning.

As Scott had mentioned, net income was $130 million for the quarter, or $1.09 per diluted share. The quarter did include two items, the Alaska Petroleum Production tax credit where we got another refund this quarter. That was $11 million before tax, $7 million after tax, for $0.06 included in the $1.09. Also, we did have some discontinued operations, mainly associated with Argentina, for $2 million, or $0.02 for the quarter.

So great quarter, reporting. Obviously our financial results are continuing to improve, as Scott and Tim both mentioned. Production is steadily growing. Margins are continuing to improve. And cash flow is increasing substantially and I will talk a little later in the slides about 2009 cash flow jumping 50%.

Turning to Slide 24 and looking at oil realizations, you can see in the green bars oil price realizations were down 3% for the quarter. That’s primarily due to a reduction in VPP deferred revenue amortization in the quarter. Also, we had incremental hedges in place in the first quarter 2008 relative to the quantitative hedges we had in place in the fourth quarter, and so that decreased our price realization slightly, obviously offset by the rise in oil prices.

NGO prices were up 5% quarter-on-quarter, primarily due to higher liquid prices. Similarly, gas prices were up 7% quarter-on-quarter, given the run up in gas prices. You will also note there that, in the light blue, the $0.40 decrease in VPP deferred revenue resulted from one of our gas VPPs running off at the end of 2007.

Turning to Slide 25, we talk about production costs. Production costs were up 12% relative to the prior quarter, about 8% relative to the midpoint of our guidance. Two principal components of that was one, production taxes were higher in the quarter than we anticipated due the higher commodity prices so that was part of it. Ad Valorem taxes obviously are going up with our rising commodity prices, as well.

When we look at LOE we did see, or are starting to see, the effects of the commodity price increases on our higher fuel and power costs that we’re starting to see. So that increased our base LOE some. We also had some compressor maintenance going on in the Raton area to improve the efficiency of our compression system up there. And so that added some costs. Obviously, as Tim mentioned, Sable has a fixed-cost component as related to the FPSO, so when you couple that with the declining production it causes us to increase on a per [inaudible] basis, our LOE base cost. And in addition, with the Cherouq start up that Tim was mentioning, we had some higher costs on that start up and as the production ramps up, as Tim mentioned, in the back end of this year, we expect those to come down.

Turn to Slide 26 and look at capital invested for the quarter. We spent about $306 million of CapEx. This did include about $30 million of work that was carried over into 2008 that was originally anticipated to be done in 2007. It was principally related to work on our Oooguruk facilities in Alaska, our Cosmopolitan drilling in Alaska, and then some completions in our wells in the Spraberry and Edwards Trend areas.

We also had seismic that’s front-end loaded in 2008, during the first half, in Edwards and Tunisia. We should see a fairly substantial decrease in seismic activity during the second half of 2008.

So, overall, as we look at our capital budget over the next few months, we will be evaluating whether we should increase that budget, and it likely will given our Q on spending and recent drilling successes. We also want to take a hard look at our cost increases, given the run up in commodity prices. So I think we will be looking at that and we will come back to you and report on that, but I think it is important to note that we still expect to be well below our expected 2008 cash flow that I will talk about here in a minute.

Turning to Slide 27, and moving to second quarter guidance, we are projecting to have 110,000-115,000 BOE per day of production. That does include about 1,100 barrels per day of production associated with the public ownership in Pioneer Southwest Energy, the MLP public piece. So that’s 1,100 barrels of that.

Production costs are expected to be $12.75-$13.75, obviously reflecting the continued strong commodity price environment. Exploration and Abandonment costs are $40 million-$70 million. That’s principally associated with drilling and seismic activity that’s going on in our Edwards Trend and Tunisia areas. DD&A $10.75-$11.75 per BOE, similar to the first quarter. G&A expense $34 million-$38 million. Interest expense $36 million-$40 million. Cash taxes, a slight increase from where we guided on the first quarter of $15 million-$25 million, mainly related to Tunisia and smaller piece in the U.S.

So, overall our effective tax rate is expected to be between 40%-50%.

Turning to Slide 28. Just to give you a view of our cash flow for 2008. We have a rainbow chart here so you can pick your commodity prices and see what our cash flow is going to be. If you look at the star in the upper right-hand corner you will see we are projecting based on future commodity prices and actual results to date of cash flow of $1.4 million. So obviously as we go through the year and continue to post actual results, the sensitivity of that will decrease.

Turning to Slide 29 and looking at 2009. Scott mentioned we are expecting to be about $2.2 billion of cash flow for 2009, a 50% increase from 2008. And obviously as Tim went through the assets with the legacy hedges rolling off and the production growth from our core areas, we are looking forward to 2009 and reporting actual results on this cash flow.

With that, we will turn the call over for Q&A. I will remind people that we have supplemental information, there is an index on Slide 30, so I would encourage you guys to look at that. But we will go ahead and open the call up for questions at this point.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Gil Yang with Citigroup.

Operator

Gil Yang – Citigroup

Comment on why you’re focusing on where you drilled into Kp1 and you’re now looking at Kp2 and Kp3. Was there anything in particular about those horizons that made you target them first and does that give us an idea of what to expect for the other formations?

Scott D. Sheffield

We focused on the deeper part of the basin and through our core analysis that we completed in the last several months, the deeper part is the most organic-rich portion of the entire intervals, that’s why we focused on Kp1.

And Kp2 and Kp3, we’ve sort of ranked them as to compared to Kp1 to Kp2 and Kp3 are better than Kp4 and Kp5, so that’s why we’re slowly moving up coal.

So it’s deeper, it’s more organic-rich, is the primary reason.

Gil Yang – Citigroup

Do you have a gas-in-place number per section for each of the different Kps?

Scott D. Sheffield

I don’t think so yet. At this point in time it’s mostly more Kp1 is where most of the reserves are.

Gil Yang – Citigroup

Can you quantify that in any way?

Scott D. Sheffield

Well, Tim read the numbers.

Timothy L. Dove

Yes, I think we think the overall gas in place, underneath the 134,000 acres we have, is 21 TCF. We’re talking about, Gil, if you saw that slide, about 2 TCF, that’s just Kp1 in those identified areas. What we don’t have for you yet, until we get some more well control, is what sort of number we could increment that with by adding Kp2 and Kp3.

Gil Yang – Citigroup

You don’t know yet how different Kp2 and Kp3 are from Kp1?

Timothy L. Dove

We’re just doing that work right now.

Gil Yang – Citigroup

Can you just talk about the free cash flow? Your plans for that going forward.

Scott D. Sheffield

It’s a combination of continuing to look at both owned acquisitions. We think it’s important to get our balance sheet where [inaudible] look at their exhibits of 48%. Our target level is 35%-40%. We’ll do that with a combination of strong earnings this year and next year. We want to get back down to 35%-40%, stay long term. Continue to buy stock up when we see opportunistic times during stock dips. We will see some CapEx run up over time. Obviously, expanding areas in the Pierre and the Spraberry Trend areas. So it’s a combination of all that.

Gil Yang – Citigroup

Last question. You said that Edwards is already at your exit rate. Can you just comment on what drove it there so quickly. Is it just levels or well performance or maybe quantify it a little bit.

Scott D. Sheffield

It’s basically, we’ve had about nine discoveries. In these last two discoveries we announced late last year, by the end of the third quarter, early fourth quarter, the rock and the permeability is much better and the wells are coming on 10-18 million a day versus a typical well around 4-5-6 million a day.

So several wells are coming on at 10-18. In fact, the wells that are producing today are curtailed significantly. So even with the sustained gas that Tim talked about, we have another two or three wells that are basically curtailed back and that’s the basic reason why.

So, when you look at all the discoveries that were made back in the 1960s by the majors in the Edwards Trend, some of them averaged about 4 BCF per well and some of them averaged about 10 BCF per well.

And so it looks like we’ve hit a sweet spot in two of our discoveries that hopefully will generate something on the magnitude of 6-10 BCF per well.

Gil Yang – Citigroup

Can you identify what the sweet spots are against the others or do you know yet what . . .

Scott D. Sheffield

I wish our geologists were that good. So we’re happy with our discoveries’ success. So if you want to get a more detailed geologic review, Frank will set it up with Christie after this call. And it’s basically, I’ve been told, a bunch of geologic creatures that are in this part of the reef that increased frosting and permeability. Significantly.

Operator

Your next question comes from Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

Turning to Spraberry when you look at your accelerated drilling program there and the vast resource potentially you identified, how should we think about reserve additions this year through developed versus undeveloped?

Scott D. Sheffield

The 20-acre infield drilling, we had the latitude on about 200-300 locations that we have through what they call against the exception. We don’t have to get the railroad commission approval. Those are not booked at this point in time. And then we’re going to go to the Texas Railroad Commission later this year and apply to add 20-acre spacing to 160s. Right now you can drill on 160s, 80s, 40s, and then we will propose optional 20s.

So we will continue to improve because of this, improve significantly with water flooding going to online and also the horizontal work that we will be doing will continue to improve it significantly also.

Brian Singer – Goldman Sachs

Can you talk about the competition there for additional acreage as well as any changes in cost structures as a result of higher oil prices?

Scott D. Sheffield

Right now, pretty much in all of our areas, timber goods, because of steel costs and what’s happened to coal, timber goods are moving up. We’ll see some impact this year, more impact going into 2009. Steel, I expect to go up. Most of our pumping units already bought for this year, so going into 2009 we will have a bigger effect, anything associated with steel. Pumping services came down significantly going into this year. So right now we haven’t seen any major issues for 2008. As we increase activity.

Brian Singer – Goldman Sachs

And Spraberry specifically are you seeing any increased competition in response to higher commodity prices?

Scott D. Sheffield

The recount has picked up in the Spraberry Trend area. And pretty much a lot of it is on the west side where you’re making a little bit better Wolfcamp wells. We’re still going to the Wolfcamp play, so we have seen activity pick up.

Brian Singer – Goldman Sachs

And lastly, any additional opportunities you see in South Africa given some of the energy issues going on there?

Scott D. Sheffield

No. Right now at this point in time we have a strong profile with our biggest gas well coming on by the end of this year and early next year, through 2012. And at this point in time we don’t see any additional opportunities. The only additional opportunity I think Tim mentioned is that we will be able to produce the Sable oil field in early 2009 without the FPSO. So we’ll have the benefit of both gas and oil at a very low operating cost.

Operator

Your next question comes from Nicholas Pope with JP Morgan

Nicholas Pope - JP Morgan

Quick question on Edwards Trend. I was wondering if you had an idea of how much some of the infrastructure costs, that you mentioned are going to be there? And also, how sour is the gas that you’re seeing in the Edwards Trend?

Scott D. Sheffield

The gas is very minimal with regards to sour. We do have to sweeten it enough to get it to specs into the pipeline.

Timothy L. Dove

The infrastructure costs are probably about $25 million this year. Across the trend.

Nicholas Pope - JP Morgan

And then, moving over to the Spraberry, what is the major bottleneck that you have in terms of ramping that development up to try to get those 9,000 you were talking about?

Scott D. Sheffield

There really isn’t a bottleneck. We stated it is very important for us to establish a free cash flow model. It’s important that we do it in 2008 and going forward. The second part of the equation is that we do see a major ramp up and we’re going to do it in a way, as Tim mentioned, to not tax the employee base and the service infrastructure.

Timothy L. Dove

To give you an idea, we have had 26 rigs running out there before. So, this isn’t our first rodeo when it comes to cranking up drilling campaigns.

Operator

Your next question comes from Robert Lynd from Simmons & Company.

Robert Lynd – Simmons & Company International

Tim, just wanted to get your thoughts on sort of the Pierre Shale and the different zones there. If the number 2 and number 3 zones are producible, that’s going to be a pretty thick zone if you include all three members, about 1,400 feet, which probably would make it better from a vertical program. Is that sort of your thought?

Timothy L. Dove

Well, I guess let me say, first of all, we don’t have any thoughts until we get some wells producing for a long enough time. I think you are right, if you look at the thickness of the Kp1, it may lend itself to horizontal drilling in a significant way and that’s the objective of some of the drilling here in the second quarter. I think if you start thinking about major productivity in the Kp2 and Kp3 you’re exactly right. You have 1,100 feet there and probably vertical wells in those sections are what makes sense.

But I just got to tell you, it’s early days, we’ve got to see some of the well performance before we can make that decision. But I think you’re on to something there, based on we’ve got 2,600 feet of shale here so it’s not your normal issue where you’re dealing with 200-300 feet.

Robert Lynd – Simmons & Company International

And can you remind me how far below your lowest coal seam the Kp1 shale is?

Timothy L. Dove

Depending on where you are in the basin, you’ve got the coal between 1,500 and 2,500 feet and the shale typically starts at 4,000 and goes down to 6,000, let’s say. So the bottom of the Kp1 is typically 6,000 feet.

Robert Lynd – Simmons & Company International

And with your service assets in the area, I think you have a couple of rigs, one conventional and a coil-tubing unit. Let’s say you move towards horizontals, will these rigs be capable of drilling a horizontal that deep in the Kp1?

Timothy L. Dove

I think that they are capable. The issue is I think we would probably bring another rig in that’s more efficient, because the rigs we have now are very focused on cheap vertical drilling. They can achieve the horizontal section but we probably need to bring in an additional rig to really make it a lot more efficient to drill a horizontal section. That’s what we’re contemplating as we speak.

Robert Lynd – Simmons & Company International

If you move towards a vertical program would they be able to handle that?

Timothy L. Dove

Sure, no problem.

Robert Lynd – Simmons & Company International

And what about your frac fleet? Do you typically do nitrogen foam fracs on the coal?

Timothy L. Dove

That’s correct.

Robert Lynd – Simmons & Company International

Are your thoughts more toward slick water?

Timothy L. Dove

Yes. That’s one of the things we’re doing, is we’re unlocking the keys to the proper completion techniques in the Kp1 and I think that’s the direction it would go.

Operator

Your next question comes from Leo Mariani from RBC.

Leo Mariani – RBC Capital Markets Corporation

Quick question here on the Edwards Trend. Just trying to get a sense of what you think the timing is on terms of bringing infrastructure in and getting some production. Are there a couple of points in time you guys are looking at where you can get some of that behind pipe production?

Timothy L. Dove

I think it’s essentially through the year, Leo. In other words, we’ve got some new production capability that we’ll have here, even in the second quarter. And then we’ll have some that comes on as we get in the third and fourth quarter. So I think it’s going to be somewhat ratable throughout the year. By the time we get to the end of the year I think we’ll have that 25 million a day that we referenced.

Leo Mariani – RBC Capital Markets Corporation

And you guys are doing all your drilling out there on seismic, I presume. Are you guys seeing, on your seismic, some of these better areas and where you’re drilling? Is that what’s giving you some of the better results recently?

Timothy L. Dove

Let’s put it this way. By virtue of having shot the 3-D, we’re adding new exploration targets. It’s hard to have the imaging tell you where you’re going to have sweet spots in terms of rock quality, but we are confident we’re adding new drilling locations in addition to more accurately depicting the subsurface so as to properly orient the horizontals, as well. So I think it’s a combination.

Leo Mariani – RBC Capital Markets Corporation

Jumping over to Barnett, how many wells do you guys expect to get drilled here in 2008?

Timothy L. Dove

Well, I think we’re probably looking at a total of about 20 wells. Combination of wells that we’re drilling with another operator up in Wise County and in addition to which we are drilling with our rig, as we speak, several wells this year, probably about 14-15 wells. So overall, about 20 wells.

Leo Mariani – RBC Capital Markets Corporation

And if you look forward you talked about increasing that a fair bit. What would you see for a well count there?

Timothy L. Dove

It’s a little early days for 2009 capital budgeting. I would say definitely we will be adding a few rigs in Barnett, to get after the ramp up. In some of the past discussions we have talked about perhaps getting up to five rigs in 2009.

Operator

Your next question comes from David Tameron from Wachovia Securities.

David Tameron – Wachovia Capital Markets, Llc

On the Edwards Trend you just talked about, if you look at it, you said you had 20 million [inaudible] but if you continue to grow at the current rates you’ve been growing at, obviously you start hitting the wall pretty quickly. What do you foresee coming out of that region? For 2008 production growth? Is that 25% target still a good number?

Scott D. Sheffield

Obviously we say greater than 25%. We will probably have a much better feel on some expansion negotiations that are going on in August, so we’ll probably come out with a much stronger number in August.

David Tameron – Wachovia Capital Markets, Llc

I’m just trying to figure out what you’re going to do for capacity because 25% gets you just under 70. You’re at 70 today. Is this going to be constrained? Am I reading that right?

Scott D. Sheffield

Tim mentioned we’re going to see pick ups a little bit. You know, I can’t see it jump as fast as it did from last quarter to this quarter, but obviously you’re going to see pretty good incremental pick up somewhere in the 6-10 million a day per quarter. Then we’ll be up to 25 by the end of the year.

David Tameron – Wachovia Capital Markets, Llc

Good problem to have. The area of targeting, just looking at the map you put on Slide 16, with the hatchet. Do you have existing production above this shale in the Raton that you produce from?

Timothy L. Dove

Yes, is the answer.

Scott D. Sheffield

We have 200 million a day.

David Tameron – Wachovia Capital Markets, Llc

If you reference the actual slide there, the slide implies it comes from a different part than the existing Raton, so I was just clarifying.

Timothy L. Dove

We need to fix our art work because basically that hatchet area sits directly over the western part of the underlying face drain coal bed methane. I will get on our artist to get that fixed for you.

David Tameron – Wachovia Capital Markets, Llc

I just thought I would clarify that because I remember from the Evergreen days that they had a lot of production out west. So I just wanted to clarify.

Timothy L. Dove

That of course is towards the deepest part of the basin, Scott was referring to, when it comes to the shale. So that’s the sweet spot area and the 10 wells we drilled, in essence we call five of them having been drilled in the fairway. We’ve had pretty good production results and we’ve delineated this 134,000 acres that surround that hatchet area with five additional wells. And some of these wells are 20 miles apart, to give you a feel. So, we’ve done a bunch of work to delineate but we have about 1/3 of our CBM acreage that we think is sort of the sweet spot of the Pierre.

David Tameron – Wachovia Capital Markets, Llc

Going back to Spraberry, when you put out the, I guess it was in early April, update about Spraberry and Pierre, you mentioned about the Spraberry, the recovery factor is now up to 12%-13%. Do you recall what the number was previously that you guys were using for an estimate?

Scott D. Sheffield

The 12%-13% was through 40-acre spacing. And then we’re going to 18%-19% with 20-acre spacing. And then you add another 9% to get to 27%.

David Tameron – Wachovia Capital Markets, Llc

And prior to that?

Scott D. Sheffield

12%-13%. It’s always been 12%-13% for the last several years.

Operator

Your next question comes from Rehan Rashid with FBR Capital Markets.

Rehan Rashid – Friedman, Billings, Ramsey

Couple of housekeeping items. On the South African front, what is going to be the savings from the release of the FPSO?

Scott D. Sheffield

The only thing I know, it’s $180,000 a day contract.

Timothy L. Dove

Here’s the math. $30 per BOE op cost in South Africa today. That’s going down to a very low number when the FPSO is gone.

Rehan Rashid – Friedman, Billings, Ramsey

I like that. On the Edwards Trend front, you do mention 25-50 million a day with additional capacity. From what it looks like you could very well blow through that pretty quickly. What would it take to add an incremental layer of whatever you would need, or some portion of that?

Scott D. Sheffield

There’s a longer-term approach and there’s a short-term approach. And the short-term approach is more aiming units and aiming units basically swings the gas to put it in the specs of the pipeline. And so we can add more aiming units. Or we can build a bigger, larger gas plant. And we haven’t made the decision yet. That decision will probably be made over the next three to four months.

Rehan Rashid – Friedman, Billings, Ramsey

As you drill up more wells, I presume, and see . .

Scott D. Sheffield

Yes.

Rehan Rashid – Friedman, Billings, Ramsey

Speaking of that, on Edwards Trend, the sweet spot that we were just talking about, how much of your acreage position or how much of the discovery size could I presume covers that sweet spot?

Scott D. Sheffield

Of the 200 locations we show on our chart, it’s about 50 locations. So it’s about a quarter right now. And that’s all basically in the probably category. And hopefully the 3-D seismic will continue to add to that inventory.

Rehan Rashid – Friedman, Billings, Ramsey

And how much reserves resource potential would that imply?

Scott D. Sheffield

We’re showing about 100 million barrels. I think that number will continue to go up, but it would be more than 25% of that because it’s better welled. But we need more history. Our first well only has three months of history and it’s curtailed back, significantly. So we need a lot more history. We need at least nine months of history before we can really determine is it going to be a 6 BCF, 8-10 BCF well.

Rehan Rashid – Friedman, Billings, Ramsey

So by year end we will have a good feel for what kind of RP ratios you will have for a good chunk of the discovery here.

Scott D. Sheffield

Yes.

Rehan Rashid – Friedman, Billings, Ramsey

On the Spraberry, the horizontal well, could you talk a little bit about the well design and some thoughts that went behind that well design? How long is the lateral, how many frac stages, what kind of frac?

Scott D. Sheffield

The well design was designed 10-15 years ago, so we took a portion of our wells through the upper Spraberry and a portion through the lower Spraberry, so the horizontal wells are actually drilled 10 years ago. So all we’re doing right now is going back in, and I’ve told people that 25% of our wells did much better than vertical, 75% did not. We did not stimulate any of those wells. So they fraced every Spraberry well generally. And so the fracture technology was too expensive at the time.

We’re going back in those wells now and the first well, if you look at a decline curve in the back of the exhibits on our slides, it comes in 50 barrels a day and starts falling off immediately. So the first well had been producing at 50 barrels a day for about three weeks now. Really steady and high volume. So that’s the encouraging thing.

So, as Tim mentioned, we’re fracing two more wells. We’ve got a total of five. If they all look positive we’ll probably go back in and frac the other 15. And then the next step is probably designing a new horizontal well from scratch.

Rehan Rashid – Friedman, Billings, Ramsey

Any need to know at this point how hard you’re fracing this thing?

Timothy L. Dove

Here are some details on it. It says an existing well drilled open hole in the 1990s, 1,600 foot lateral in the lower Spraberry section, put four stage frac on it with gel/water mix and that’s the only well we have results on so far. But that’s the concepts.

Operator

Your last question comes from Joe Manger with Tristone Capital.

Joe Magner - Tristone Capital

Just curious on the Spraberry waterflood, what’s the design of the pilot? And what’s the sort of goal of that?

Scott D. Sheffield

It’s to get another 9% out. We conducted a number of successful pilots over the last 10 years, Joe. The goal is to get another, with the 20-acre spacing, it allows us to expedite the movement and it will be less fill up time as we start injecting water. The Spraberry produces about two or three barrels of water for every barrel of oil so we have natural water, formation water, we will be injecting in. And so the 20-acre spacing coupled with secondary recovery, we should be able to see response fairly quickly in a six-month time period.

And the goal is to get another 9% of the oil out.

Joe Magner - Tristone Capital

Is this in an area where you already have a pretty effective 20-acre pattern drilled?

Scott D. Sheffield

No. We have 40 acres so we’ll do in and drill 20s in a couple of targeted areas and convert half of the 20s to injectors. We haven’t decided whether to line drive or a [inaudible] yet.

Joe Magner - Tristone Capital

And the historical waterfloods Tim mentioned, have those been a variety of patterns or have those been similarly designed in the past?

Scott D. Sheffield

They were a variety of patterns by the majors in the 1960s. We’ve basically had a middle line drive in our recent pilots.

Joe Magner - Tristone Capital

Switching over to the Pierre. The new wells that are being drilled, are those twins off of existing pad locations that are producing from CBM?

Timothy L. Dove

I think that’s one of the benefits, of course, that we have CBM wells where we can drill from existing pads. Actually, some of the newer wells are new pads, of course, but as we look ahead to the development planning, we have a substantial number of wells we can drill from existing pads.

Joe Magner - Tristone Capital

And how does the pressure vary in the Pierre versus another shale or CBM?

Timothy L. Dove

Your Pierre is just slightly, subtly below normal pressure. Of course your CBM is very low pressure. So we would be talking about different systems, but we’ve got plenty of compression out there to basically optimize surrounding that so I don’t think that’s going to be an issue in the field. In fact, it may help us in a lot of coal bed areas.

Joe Magner - Tristone Capital

And on the take away front, are you working with CIG to expand capacity or do you still have enough cushion for some period of time before that becomes an issue?

Timothy L. Dove

I think we’re looking at the latter part of this decade or into early part of the next decade before we really need to have capacity. But we’re working on it now to be prepared and so that’s what we’re doing. As I mentioned, we’re working more towards northern markets in the next traunch of outtake from the field.

Joe Magner - Tristone Capital

And in terms of South Africa, I might be remembering this incorrectly. I thought the FPSO was being updated to handle oil and gas production simultaneously. Is that not the case?

Timothy L. Dove

No, actually what you’re referring to is the fact that if we move crude oil and natural gas down the pipeline in a co-mingled fashion, it’s really the gas-to-liquids plant that needs a small renovation. So the FA platform may need a little bit of work in terms of handling liquids but basically your bigger issue is, and it’s not a large issue, it’s solvable with a little capital infusion, is ramping up the gas-to-liquids plant onshore to take a liquid slug.

Operator

I would like to turn the call back to the speakers for additional or closing remarks.

Scott D. Sheffield

I want to thank everyone for taking the time. I know it’s a busy schedule for everyone. Looking forward to seeing everyone on the road at these conferences or we’ll see you in August at our second quarter call. Again, thanks. We had a great quarter and we will continue it.

Operator

Thank you for participating in today’s conference call. You may now disconnect.

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