先鋒自然資源 (PXD) 2008 Q1 法說會逐字稿

Welcome to Pioneer Natural Resources first quarter conference call. Just a reminder, today's 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. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website select Investor, then select Investor Presentation.

The Company's comments today will include forward-looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in the last paragraph of Pioneer's news release, on page two of the slide presentation and in 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. Please go ahead, sir.

Good day, everyone, and thank you for joining us. I'm going to briefly review the agenda for today's call. Scott's 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, Time 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 from 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 S Southwest Energy Partners announced the 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 the this call and in meetings with investors and analysts over the remainder of May. With that, I will turn the call over to Scott.

Thanks, Frank. Good morning and, again, I'm going to start out on slide three, for people that have access to these slides. 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 110,000 barrels of oil equivalent per day, at the very, very high end, we're actually over guidance that we gave last quarter. We are up 24% versus 12 months ago, first quarter 2007. And 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 growth of 14% (inaudible) through 2011. That's especially starting out with a strong very first quarter. Discretionary cash flow is up 65% versus first quarter of 2007. We have also, with the recent price movement of 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 850 flat we are at $109 per share and at $100 oil flat and $10 gas flat, we're at $153. So it's important we're continuing to add net asset value each year with our program.

Also, we did close yesterday at $163 million in proceeds our transaction with Pioneer Southwest Energy Partners. Slide number four, Operational Highlights, again, we made a major announcement, things we have been working on for a little over a year, in regard to the Spraberry trend area field that represents over half of the Company. There's another billion barrels of oil equivalent of resource. We started drilling on 20-acre spacing, in-field drilling earlier this year. Very positive results. Tim will talk more about it. And then secondly, we probably do this before our time, but we went out and drilled several horizontal wells before the stimulation technology was there about 10 to 15 years ago. We are going back in and getting very positive results by going back in and using the isolation packers type technology to frac these wells and getting excellent results. We 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, continued to see very, very positive results with our wells. Also, we had a great quarter in regard to three new Silurian wells in Tunisia which will continue to add to our production. And then what's also- what's very interesting too with being in the [Godamis] basin, one of the most prolific basins in the North Africa, our geophysicists and geologists are starting to work the seismic much harder. But we've had two nice discoveries tested at about 3,500 barrels a day equivalent in the Ordovician and the TAGI formation. One is deeper than the Silurian and one is much shallower. So it's 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 [Aguri] with first sales expected late summer. Slide number five just again shows how consistent production growth with our strategy began about two years ago. We are seeing obviously very strong quarters, very consistent production growth, and we'll continue to see that with all of our operations, again up 24% over the last 12 months. Slide number six, again just an emphasis. Most people have seen this slide. We will continue to believe in our 14% per share CAGR. Obviously we think we will do better than that, based on the first quarter and how everything is doing between now and 2011. This assumes no additional share repurchases over the next four years.

Slide seven, again just to reemphasize the strong returns at various pipe stacks, both at $70 where we test everything at 70 and 7 flat, our high case 95 and 9. Obviously, we are seeing much better returns today. But we are still being conservative in where we look at allocating capital. Still very, very strong returns in all of our key assets, as shown here. Eight is just a reminder to people that our legacy hedges are rolling off at the beginning at the end of this year, so about six to seven months left and continuing to roll off, adding about $600 million of pre-tax cash flow, cumulative, by the end of 2012. Slide number nine, again, we are targeting 20% growth and 20% compounded growth rate, after tax cash flow. I think the big focus right now and Rich's, when he goes over his financial section, is that we are 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 is over a 50% increase from 2008 in after-tax cash flow for Pioneer going into 2009.

Slide ten, 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 and Raton with the Pierre Shale and its- in this workover the last 12 to 18 months. So again, we added significant resource potential. We are up to 2.8 billion barrels of oil equivalent. Slide 11, a little bit more detail on our net asset value. What makes up the $109 and $153, proved at the 85 and 850 case is $53. At the $110 case, proved is $72. So still a lot of running room. We think it is important to focus obviously the allocation in capital on continuing develop our [PUDs], our probables in each of those categories to realize the net asset value, the upper limit at those prices. This is all at 10% discount after tax. Slide number 12, as Frank said, we can't say a lot about the Pioneer Southwest Energy Partners but we had a very, very successful offering. MLP was obviously foreign to acquire oil and gas assets in Texas primarily this 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. MLP will buy the proved developed reserves on bolt-on acquisitions and Pioneer, 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.

In slide 13, again on summary, we are on track to deliver our target of 14% plus CAGR through 2011. We have a tremendous low risk inventory to support that repeatable, consistent production growth over the next several years, again targeting greater than 20% after-tax cash flow CAGR. Again, from 2008 to 2009 we will see a 50% increase in cash flow from about $1.4 to about $2.2 billion. And then earnings expected to double in '09, triple in '09 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 are still trading well below our net asset value. Let me turn it over to Tim.

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'd take a few minutes to provide some color on the two major important resource play initiatives that Scott has alluded to and we have been discussing. And I will touch on those prior to talking about developments in some of our other core areas. The first, on slide 14, is a 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's 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 oil fields, in fact the only one that's been growing in the last five years. We know that 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 are really dealing with here is a big field that is getting bigger and doing come 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% to 13% recovery rate in our areas of operation. And as to the unbooked potential on 40-acre spacing we would say that's about approximately 200 million BOE net to Pioneer. One of our major new initiatives, of course through, is to plan to further downspace the field to 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'll 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 down-space is increase our recovery rates from that 12% to 13% to, say, another 6% or so, 18% to 19%.

In addition, we are actively working on implementing a large water flood beginning next year. That will be one of many water floods that have actually been undertaken in the field. There have been about ten water floods put in place since the '60s. 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 .5 barrels the case of the water flood. So the resource potential is enormous on that basis. And we believe that in the areas where we water flood, we can actually increase recovery rates an additional 9% which would be, if you calculated it across that approximately 40% of the acreage, about 300 million barrels. So it is pretty easy to see that we have 1 billion barrels of resource potential, roughly, in this field that is currently unapproved. 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 have already planned to frac five wells this year and have already frac'd one and have two underway. The results look excellent and I think there will be applicability in certain areas of the field, especially when surface issues will call for horizontal drilling. And so this is something that we're actively pursuing. We will be- 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 bit 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 '07 to first quarter '08 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 the bottom line, when it comes to the kind of resource potential 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 results of which will be, not only will we be able to produce a CAGR growth rate of 15% in the short term but also in the long term through 2011 by ramping up drilling in this field, taking advantage of that enormous resource potential.

And turning to side 16, this is news as of about a month ago but it's not so new in terms of Pioneer in the sense we have 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 that's worked so well on coal bed methane. We have drilled now several wells. We drilled about 10 vertical wells in the play. And in fact, we have one well that has 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 are 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 that is - you see the Kp1 270-foot shale at the bottom 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 definitively, vertical wells at a minimum in Kp1 are economic, generating some 40% IRR based on $8 gas. Of course, now what we are trying to do is enhance what this new field can give us. And there is 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 book reserves. We have booked some reserves at the end of '07 and it will be a significant contributor to reserve bookings at the end of this year and in 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 then also we're additionally testing the Kp2 and 3 sections, as shown. That's about 1,100 or 1,200 feet of shale as well. And the earlier results look very encouraging for that. We are seeing contribution from those zones in some of these new wells. And I believe we will have contributions from Kp2 and 3 when it comes to several areas of the field. And that will then contribute to our recovery rates, I think. It will only enhance the economics I mentioned. So we are very excited about Pierre. We are sort of fortunate, needless to say, this is underneath our existing coal bed, which gives us a lot of transaction 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 have already drilled about 42 coal bed methane wells and four Pierre Shale wells with very good results. We will probably be ramping up drilling in '09. And that will lead us to the CAGR growth rate in Raton of 10% to 15%. If you look a the green bars in the middle of the slide, you can see our production was up dramatically in the first quarter '08, compared to first quarter '07. 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% to 11% range. So Raton continues to produce and produce well. And that gives us confidence, of course, 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 are doing is we're adding firm transportation out of the market, in this case, to northern markets. Most of our gas today, of course, goes to mid-continent markets. So the Pierre Shale is really enhancing Raton and it really adds life to what's been a phenomenal asset for Pioneer.

In slide 18, changing the subject now, a couple of our core areas that are really growing dramatically. We start with Edwards. We continue to have a great deal of success in Edwards, as evidenced by the production growth we have seen. If you look at the bottom again in the center of the graph, you will see production is at about 70 million cubic feet a day for the first quarter. That is up about 65% from the first quarter of '07 and essentially, as Scott already mentioned, at our year end exit rate based on a 25% year-to-year growth rate. And that is coming from the fact we have drilled a large number of very strong producing wells in the large fields that was discovered in 2007, excellent rock quality which has led to really strong rates, 10 to 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 in gas processing along this 200-mile trend.

We think we will 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 to 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'll be done with that by the end of '08. Of course, that is needed in order to properly image the reef trend and understand exactly where these horizontal wells should be drilled and where the best faces is for the drilling of the wells. And you can see so far we have 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 are just starting up our activity. It is early days for Pioneer in Barnett. 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 but the production is just being tied in. But I think these wells are going got 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, of course, is we are starting this from such a low base, it can have a nice impact on Pioneer's growth rate. At current rates, it is about 15 million cubic feet a day. 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. Just like Edwards, we have had a great deal more success in this key growth area. And you can see have, as Scott already mentioned, three new Silurian wells having been drilled in the first quarter successfully. Importantly, a couple of wells that tested the new zones that Scott referred to, the Ordovician, the TAGI, the TAGI being about 1,000 meters above the [Akakis] and the Ordovician about 600 meters below it. But combined, they tested 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 are 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 [Anagi] but in [Cherute]. Incidentally, [Cherute] you may see in some of our publications now, is the area that's been designated as the producing concession that was a part of Janein Nord. So we have had several discoveries in Janein Nord and part of that has been carved out as a producing concession, called [Cherute]. And so you will see us now refer to production from [Cherute] as one of our key contributors in terms of growth in Tunisia in addition to Adam and [Borgelcadra].

The [Cherute] facilities, incidentally, are on schedule. We did start production up in the late part of 2007 but, of course, since we 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 '08 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 are seeing an increase in production as we tie in new wells as infrastructure is put in place. Today in [Cherute] 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 of course then is a ramp up of production. The wells are drilled, they're ready to be tied in. It is simply a matter of getting tankage put in place in the field and we will see production ramp up. It will 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 have 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 project, slide 21. Not a lot of news to report here other than to say we are 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. One of the reasons hat is significant is because the cost of that facility is significant in the context of oil production on decline. And it 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. At 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. The [Aguric] drilling is underway. We have drilled our first producer. We will have- in fact we're 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. And in addition to which, of course, this is a water flood project from day one. There will have several injectors drilled as well. Of course, there's about 50/50 producers and injectors when you look at the overall plan of development.

So what we can anticipate then is we will begin to- we have producing wells available, we aim to have enough producing wells for flow assure. 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 producing or processing the oil. And it should be- that is, net production should be about 3,000 to 4,000 barrels a day by the end of the year. At Cosmo things are progressing really more in terms of the permitting and facilities work. And we are planning on drilling 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 years after that. So that completes my comments and so I will pass it to Rich for a discussion of the quarterly financials.

Rich Dealy. Great, thanks, Tim, and good morning. As Scott mentioned, net income was $130 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 that 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 bit 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 all 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 '08 relative to the quantity of 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. NGL 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, a decrease in VPP deferred revenue as a result of one of our gas VPPs running off at the end of '07.

Turning to slide 25, talk about production costs. Production costs were up 12% relative to the prior quarter, 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 to the higher commodity prices, so that was part of it. Ad valorem taxes obviously are going up with the rise in commodity prices as well. When we look at Love, we did see, or are starting to see the effects of the commodity price increases on 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 cost. Obviously, as Tim mentioned, Sable has a fixed cost component related to the FPSO. So when you couple that with the declining production, that causes us to increase on a per BOE basis our LOE base costs. And then in addition, with the [Cerute] startup that Tim was mentioning, we had some higher costs on that startup. And as the production ramps up, as Tim mentioned, at the back end of this year, we expect those to come down. Turning to slide 26 and look at capital invested for the quarter, we spent $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 [Oguric] facilities in Alaska, our Cosmopolitan drilling in Alaska, and then some completions in wells in the Spraberry and Edwards Trend areas. We also had a seismic that's front-end loaded in 2008. And during the first half in Edwards and Tunisia we should see a fairly substantial decrease in seismic activity during the second half of '08.

So, overall, as we look at our capital budget over the next few months, we will be evaluating whether we should increase the budget. And it is likely we will, given our Q1 spending and percent 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 looking at that and we're comeback 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 to 115,000 BOEs per day of production. That does include about 1,100 barrels a day of production associated with the public ownership in Pioneer Southwest Energy that MLP has a public piece. So that's 1,100 barrels of that. Production costs are expected to be $12.75 to $13.75, obviously reflecting the continued strong commodity price environment. Expiration and abandonment costs are $40 million to $70 million. That is principally associated with drilling and seismic activity that's going on in our Edwards Trend and Tunisia areas. BAD&A $10.75 to $11.75 per BOE, similar to the first quarter, G&A expense $34 million to $38 million, interest expense $36 million to $40 million, cash taxes, a slight increase from where we guided on the first quarter of $15 million to $25 million, mainly related to Tunisia and a smaller piece in the U.S. So overall, our executive tax rate is expected be between to 40% and 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 that our cash flow is going to be. If you look at the star I the upper right hand corner there, you see we're 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 to that will decrease. Turning to slide 29 and look at 2009, Scott mentioned we are projecting 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 gross from our core areas, we're looking forward to 2008 and posting 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 that has an index on slide 30, so I'd encourage you guys to look at that. We'll open up the call for questions at this point.

Thank you very much, sir. Our question and answer section today will be conducted electronically. If you'd like to ask a question, please press star one on your touchtone keypad. As a reminder, please make sure that your mute function is turned off to allow your signal to reach our equipment as well as to allow us to hear your question or comment once your line is open. We will now take our first question from [Gil Yang] from [Citi]. Please go ahead.

Hi, comment on why you are focusing on- well you drilled into Kp1 and you are now looking at Kp2-3. Was there anything particular about those horizons that made you target them first? And so does that give us an idea of what to expect for the other formations?

Yes, Gil, this is Scott. If we focus on the deeper part of the basin and through our core analysis that we completed the last several months, the deeper part is the most organic rich portion of the entire interval. So that's why we focused on Kp2. And Kp2 and 3, se sort of ranked them as to- as compared to Kp1. So Kp2 and 3 are better than 4 and 5. So that is why we are slowly moving up-hole. So it's deeper, it's more organic rich is the primary reason.

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

I don't- I don't think so yet at this point in time. It is mostly more Kp1 is where most of the reserves are.

Can you quantify that in any way? Is it, you know-

Well Tim read the numbers, so-

Yes I think we think the overall gas in place 108,000 to 134,000 acres we have is in 21 TCF. We were talking about, Gil, if you saw that slide, about 2 TCF that's just Kp1 in those identified areas. But we don't have for you yet until we get some more well control is what sort of number we can increment that with by adding Kp2 and 3.

Yes, that's what I was trying to get at. You don't yet know how much- how different Kp2 and 3 are from one?

We're just doing that work right now.

Can you just talk about the free cash flow, your plans for that, going forward?

Yes, it's a combination of continuing to look at bolt-on acquisitions. We think it is important to get our balance sheet where our debt to book, be looking at our exhibits of 48%. Our target level is 35 to 40. We will do that, a combination of strong earnings this year and next year. We want to get back down to 35 to 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 area. So it's a combination of all that.

Okay. Then last question, you said that Edwards is already your regular rate. Can you just comment on what drove it there so quickly? Is it just activity levels or well performance or can you quantity it a little bit?

Yes, it is basically, we have had, I think, about nine discoveries. And these last two discoveries we announced late last year by the end of the third quarter or early fourth quarter. The rock and the permeability is much better and the wells are coming on ten to 18 million a day versus a typical well around four to five to six million a day. So several wells are coming on at ten to 18. In fact, the wells that are producing today are curtailed significantly. So even with the sustained gas that Tim talked about at 20 million a day, we have another two or three wells that are curtailed back. And that is the basic reason why. So, if you look at the discoveries that were made in the '60s 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 obviously we have hit a sweet spot and then two of our discoveries that hopefully will generate something on the magnitude of 6 to 10 BCF per well.

Can you identify what this sweet spot is all about and see others or do you know yet what makes them?

I wish our geologists were that good. So we are happy with their discovery success. So, it's a, you know, I would call if you want to get a more detailed geologic review, call. Frank will set it up, Chris Cheatwood after this call. And it's basically, I have been told a bunch of geologic creatures that are in this part of the reef that increased porosity and permeability significantly.

Gil Yang. All right, thank you.

And our next question from Brian Singer from Goldman Sachs. Please go ahead.

Thank you, good morning.

Hi Brian.

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

. The 20-acre infield drilling, we have a latitude on about 200 to 300 locations that we have through what they call density exception. We don't have to get the Railroad Commission approval. So those are not booked at this point in time. And then we are 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'll propose optional 20s. So it will continue to improve because of this. It will improve significantly with water flooding to '09 and also the horizontal work that we will be doing will continue to improve it significantly also.

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

Right now pretty much in all of our areas, (inaudible) goods because of steel costs and what's happened to coal, (inaudible) goods are moving up. We will see some impact this year, more impact going to 2009. Anything used with steel I'd expect to go up. Most of our pumping units are already bought for this year. So going into 2009, will have a bigger effect. Anything associated with steel obviously, 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.

. And Spraberry specifically, are you seeing any increase in competition in response to higher commodity prices?

The rig count has picked up in the Spraberry Trend area. And pretty much a lot of it is on west side of the Spraberry Trend area where you are making a little bit better Wolf Camp wells. We are still going to the Wolf Camp and the Wolfberry play. So we have seen activity pick up.

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

No, right now at this point in time we have a strong profile with our gas- 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 oil, the Sable oilfield in early 2009 without the FBSO. So we will have the benefit of both gas and oil at a very, very low operating cost.

Thank you.

And moving on, our next question will come from JPMorgan's [Nicholas Pope]. Your line is open, sir, please go ahead.

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

Yes, he gas is not- is very minimal with regard to sour. We do have to sweeten it enough to get it to specs into the pipeline. Infrastructure costs, do you have an idea, Tim?

Yes it's probably about $25 million this year infrastructure cost across the trend.

Okay and then, moving to the Spraberry, what is the major bottlenecks that you all have in terms of ramping that development to try to get those 9,000 wells you are talking about?

There really isn't a bottleneck. We stated it is very important to us to establish a free cash flow model. It is 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 are going to do it in a way, as Tim mentioned, to not tax the employee base and the service infrastructure.

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

All right, that's all I have. Thanks a lot.

Our next question will come from [Robert Lynd] from [Simmons and Company].

Morning.

Hi, Robert

Tim, just wanted to get your thoughts on sort of the Pierre Shale and the different zones there. If the number two and number three 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?

Well, I guess what I'd say first of all, we don't have thoughts until we get some wells, you know, 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 is the objective of some of the drilling here in the second quarter. I think when you- if you start think about major productivity in the Kp2 and 3, you're 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 is early days, we got to see some of the well performance before we can make that decision. But I think you are onto something three based on you got 2,600 foot of shale here so it is not your normal issue where you're dealing with 200 or 300 feet.

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

Yes, you got the coal, depending on where you are in the basin between let's say 1,500 feet 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 typically is 6,000 feet.

Okay and then with your service assets in the area, I think you have a couple of rigs, one conventional and a coal coil tube in unit. Let's say you move toward horizontals, will these rigs be capable of drilling a horizontal that deep in the Kp1?

I think if they are capable, the issue is we probably bring other rig in that is 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 top drill a horizontal section. That is what we are contemplate as we speak.

Could they, if you move towards a vertical program, would they be able to handle that?

Sure, no problem.

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

. That's correct.

And I guess you would- are your thoughts more towards slick water?

Yes.

Okay.

It's really 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 is the direction we will go.

Okay, thanks, that's all I had.

And our next question now will come from [Leo Mariani] from RBC. Please go ahead, sir.

Yes, just a quick question here on the Edwards Trend. Just trying to get a sense of what you think is timing is in terms of bringing infrastructure in and getting some production bumps. There are sort of a couple of points in time you guys are looking at when you can get some of that behind power production increased here?

Yes, I think it is essentially through the year, Leo. In other words, we have got some new production capability that we will have here even in the second quarter. And they will have some that comes on as we get in the third or fourth quarter. So I guess it will be somewhat ratable throughout the year. By the time we get to the end of the year, I think we will have that, you know, $25 million a day that we referenced.

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

Well let's put it this way. By virtue of having shot the 3-D we are adding new exploration targets. Now then it is hard to image- it's hard to have the imaging tell you exactly 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 is a combination.

Okay. So over the Barnett, how many wells do you guys expect to get drilled here in 2008?

Well, I think we are 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'll be drilling with our rig, as we speak, several wells this year, probably about 14 or 15 wells, so overall about 20 wells.

Okay and if you look forward to '09 obviously you talked about increasing that a fair bit. What would you see for a well count there?

Well it is little early days for 2009 capital budgeting. I would say we'll be adding definitely a few rings in Barnett to get after the ramp-up. So you know in some of the past discussions we have talked about perhaps getting up to five rigs in 2009.

Okay, thanks a lot for your time.

You bet.

(OPERATOR INSTRUCTIONS). Moving on, we'll hear from David Tameron from Wachovia Securities. Please go ahead.

Hello. I guess good morning. On the Edwards Trend you talked about, if you look at it, you said you had $20 million a day today shut in. Then if you continue to grow at the current rates that you have 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 did number?

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 will probably come out with a- obviously a much stronger number in August, David.

. Okay and so there's some- I'm just trying to figure out what you're going to do for capacity because 25% gets you just under 70. You are at 70 today. Is this going to be- I mean this sounds like the second half of '07 production is going to be constrained. Am I reading that right?

Tim mentioned we are going to see pickups a little bit. You are not going to see it jump as fast as it did from last quarter to this quarter. But obviously you are going to see pretty good incremental pickup, you know, somewhere in the $6 million to $10 million a day, you know, per quarter and then we will be up at least $25 million by the end of the year.

Okay yes, good problem to have. In the (inaudible) aren't the area you are targeting, just looking at the map you put on page 16 with the [Hatchet], do you have an existing production above this shale in the Raton that you produce from? Is there infrastructure already in this part of the basin?

Yes is the answer.

Okay.

Yes, we have, you know, 200 million a day.

Yes, no I was just- if you reference the actual slide there. Yes I didn't realize you have 200 million a day but the implied pictorial from the slide was it's a little different part than existing Raton production so [crosstalk]

Yes, we need to fix our artwork, obviously, because basically that Hatchet area sits directly over the western part of the underlying face grain coal bed methane. I will get on our artist to get that fixed for you.

No I just- I just clarified because I remember from the Evergreen days that they had a lot of production out west I just wanted to clarify.

Yes that, of course, shows the deepest part of the basin Scott was referring to when it comes to the shale. So that is why 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 where we had pretty good production results. And we've delineated this 134,000 acres that surround that Hatchet area with five additional wells. And you know, some of these are 20 miles apart to give you a feel. So we have done a bunch of work to delineate that we have about a third of our CBM acreage that we think is sort of the sweet spot of the Pierre.

Okay, that makes sense. And going back to Spraberry, when you put out the, I guess, early April update right before (inaudible) about Spraberry and Pierre, you mentioned about the Spraberry that recovery factor is now up to 12% to 13% coming from the field. Do you recall what the number was previously that you guys were using for an estimate?

Yes, no the 12 to 13 was through 40-acre spacing. And then we are going to 18 and 19 with 20-acre spacing. Then you add another 9 to get to 27%.

Oh okay and prior to that-

12 to 13. It has been 12 to 13 for the last several years.

Okay and then you're up, okay that makes sense. All right, thanks. Nice quarter.

Okay, thanks.

And now we will hear from Rehan Rashid from FBR Capital Markets for our next question. Please go ahead.

Morning, Scott

Hi, Rehan, how are you doing?

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

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

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

Good, I like that. On the Edwards Trend front, you do mention 25 to 30 a day of additional capacity. From what it looks like, you could very well blow through that pretty quickly. What will it take to add an incremental layer of whatever you would need or some portion of that?

Yes, there is a longer term approach and there's a short term approach. The short term approach is more aiming units. And aiming unit basically just swings the gas to put to specs to 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. So that decision will be made probably over the next three to four months.

Okay, as you As you drill up more wells, I presume, and see the success rate. Speaking on that, on Edwards Trend, the sweet spot that we were just talking about, what- how much of your acreage position or how much of, I'll call it, discovery size could I presume covers that sweet spot?

Yes, it is about- the 200 locations we show on our charts, about 50 locations. So it is about a quarter right now.

And that is all basically in the probable category. So hopefully through the 3-D seismic we will continue to add to that inventory.

And how much reserves or resource potential would that imply again (inaudible) please?

We are showing about 100 million barrels. I don't think that number will continue to go up but it would be more than 25% of that obviously because it is better wells. But we need more history. Our first well only has there months of history and it is 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.

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

Yes.

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

The well design was designed 10 to 15 years ago. So we took a portion of our wells to the upper Spraberry and apportioned through the lower Spraberry. So the horizontals were actually drilled 15 years ago, so all we're doing right now is going back in, and over old people 25 percent of our wells did much better than verticals, 75 did not. We did not stimulate any of those wells. You have to frac every Spraberry well generally. And so the fracture technology was too expensive at the time. We're going back in those wells now and I the first well, you look at her decline curve in the back as an exhibit of our slides are on our website. It comes in 50 barrels a day and starts falling off immediately. So the first well has bee producing at 50 barrels a day for about three weeks now, really steady and high volume so that's the encouraging thing through the upper and the lower Spraberry. They were drilled years ago. All we are doing right now is going back in. I have told people 25% of the wells did much better than vertical 75 did not. We did not stimulate any of those wells. So the fracture technology. You can look at the slides. It comes in 50 barrels a day and starts falling off immediately. The first well is producing at 50 barrels a day for about three weeks now, really steady and high volume. So that is the encouraging thing. So as Tim mentioned. we are frac-ing two more wells. We've got a total of five. They all look positive. We will probably go back in and frac the other 15. And then the next step is probably designing a new horizontal well from scratch.

Okay, okay and any need to know at this point how hard you are frac-ing this thing (inaudible)

Well here's some details on it. It's a- it says existing well drilled open hole in the '90s, 1,600-foot lateral in the lower Spraberry section. Put four stage frac on it with a gel/water mix and, of course, that is the only well we have results on so far but that is the concepts.

Good stuff, thank you.

And moving on, we will hear from Tristone Capital's Joe Magner. Please go ahead.

Good morning, I was just curious on the Spraberry water flood. What is the design of the pilot and what's the sort of goal of that?

Yes, it's to get another 9% out. We conducted a couple of successful pilots over the last ten 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 to three barrels of water for every barrel of oil. So we have natural water. Formation water we'll be injecting in. And so the 20-acre spacing, coupled with secondary recovery, allowed us- 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.

Okay, so is this in an area where you have a pretty effective 20-acre pattern drilled?

No, no. We have 40 acres so we will go in and drill 20s in a couple of targeted areas and convert half the 20s to injectors. We haven't decided whether it's a line drive for five spot yet.

Okay and how- the historical water flows, the ten water flows Tim mentioned, have those been a variety of patterns or have those been similar deigns on the past?

They were a variety of patterns by the majors in the '60s. We basically have had a line drive in our recent pilots.

Okay, switching over to the Pierre, the wells that are being drilled, the new wells that are being drilled, are those twins off of existing pad locations that are producing from CVM?

Yes 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 he newer wells are new pads, of course, but as we look ahead to the development planning, be a substantial number of wells we can drill from existing pads.

And how does the pressure vary in the Pierre versus some of the shallower CVM?

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

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

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

And then 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? Is that being put on the FA platform?

Oh no, actually what are referring to is the fact if we move crude oil natural gas down the pipeline in a commingled 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 biggest issue, and it's probably a large issue, it's solvable with a bit of capital infusion is wrapping up the as to liquids plant on shore to take a liquid slug.

Okay that is all I have, thank you.

And at this time we have no further time for questions. I would like to turn the call back to our speakers for any additional or closing remarks.

Again, I want to thank everyone for taking the time. I know it's a busy schedule for everyone. Again, looking forward to see everybody at either on the road at these conferences or we'll see you in August at our second quarter all. Again, thanks. We had great quarter. We'll continue it. Again thank you very much.

Thank you, everyone, for your participation. That does conclude today's conference. Everyone have a great day.