Patterson-UTI Energy Inc (PTEN) 2008 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second quarter 2008 Patterson-UTI Energy incorporated earnings call. My name is Eric, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will facilitate the question and answer session at the end of the conference. (OPERATOR INSTRUCTIONS).

On behalf of Patterson-UTI I would now like to turn your presentation over to Mr. Geoff Lloyd. Please proceed, sir.

Thank you, Eric, and good morning, everyone. On behalf of Patterson-UTI Energy I'd like to welcome to you today's conference call to discuss the results of the three and six months ended June 30, 2008. Participating in today's call will be Mark Siegel, Chairman, Doug Wall, Chief Executive Officer, and John Vollmer, Chief Financial Officer. Just a quick reminder that statements made in this conference call that statements the company's or managements intentions, believes, expectations or predictions for the future are forward-looking statements. It's important to note that actual results could differ materially from those discussed in such forward-looking statements. Important factors that could cause actual results to differ materially include but are not limited to the declines in oil and natural gas prices that could adversely average demand for the company's services, and their associated affect on day rates, rig utilization and planned capital expenditures, , excess availability of land drilling rigs including as a result of the reactivation or construction of new land drilling rigs. Adverse industry conditions, difficulty integrating acquisitions, demand for oil and natural gas, shortages of rig equipment and ability to retain management and field personnel. Additional information concerning factors that could cause actual results to differ materially from those in the forward-looking statements is contained from time to time in the company's SEC filings which may be obtained by contacting the company or the SEC. These filings are also available through the company's Web site or through the SECs Edgar system. The company undertakes no obligation to publicly update or revise any forward-looking statements.

Now it's my pleasure to turn the call over to Mark Siegel for some opening remarks to be followed by questions and

Thank you, Geoff. Good morning and thank you for joining us today. I hope that by now all of you have had an opportunity to read our earnings release, which was issued earlier this morning prior to the opening of the market. I plan to begin by taking a couple of minutes to review briefly the financial results for the just completed quarter. I'll then turn the call over to Doug Wall, Patterson-UTI's President and CEO, for some brief color on our operating rule. As always we will be pleased to take your questions following these prepared remarks.

Today, we reported net income of $81.4 million, or $0.52 per share for the three months ended June 30, 2008. Compared to net income of $140 million, or $0.88 per share for the three months ended June 30, 2007. Revenues for the second quarter of 2008 were $526 million, compared to revenues of $523 million for the second quarter of 2007. We reported net income of $159 million or $1.02 per share for the six months ended June 30, 2008, compared to net income of $255 million, or $1.62 per share for the six months ended June 30, 2007. Revenues for the first six months of 2008 were $1.03 billion, compared to revenues of $1.07 billion for the six months of 2007. The results for the three and six months ended June 30, 2007, include pretax non-recurring gains of $58.4 million, resulting from the sale of certain E&P assets and the recovery of embezzled funds. These gains, net of tax, increased our net income for the three months and six months ended June 30, 2007, by $37.9 million or $0.24 per share. Today, I'm also pleased to report that our board declared a quarterly cash dividend on our common stock of $0.16 per share to be paid on September 30, 2008, to the holders of record as of September 12, 2008.

I would now like to turn the call over to Doug Wall for a discussion of our operating results.

Thank you, Mark, and good morning. I'd like to make a few brief comments on each of the operating divisions and I'll start with the drilling company. For the quarter ended June 30, 2008, the company had an average of 244 drilling rigs operating, including 242 rigs in the U.S. and two in Canada. Compared to the first quarter, our U.S. rig count increased by ten rigs, and our Canadian count decreased by a like amount.

Our drilling business over the quarter saw an accelerating improvement in the U.S. rig count. This very positive trend is shown by the average of 238 rigs operating in April, 242 rigs in May, and a jump to 248 rigs working in June. We estimated that our average rigs operating in the U.S. will increase to 258 rigs for July. Strong evidence of this further acceleration. As is usual, our Canadian utilization declined dramatically due to break up, which was early and long this year. We averaged zero rigs working in Canada in both April and May, but finally saw some rigs go back to work in early June. In June, we averaged five rigs operating. We expect that we will average 11 rigs operating in Canada for July.

Overall, average revenues per operating day during the second quarter were $18,740, compared to $18,900 in the first quarter, a decline of $160 per day. Average direct cost per operating day were $11,300 for the second quarter, up from $10,990 in the first quarter. These increased daily costs were impacted by start up costs to put additional rigs back to work, mostly in the latter part of the quarter. These additional start up costs were consistent with prior upcycles. Overall gross margins declined by $468 per day from Q1. At the end of the quarter we had 41 rigs working under term contracts, which had an original term of a year or more. Along with these increased activity levels, we are also seeing improvement in our pricing levels, particularly in the 1000 to 1500-horsepower category. With the majority of our rigs working in the spot market, we feel we are well-positioned to benefit from the expected improvement in rig rates.

Now let me turn to a few operational highlights for the quarter. We introduced four new rigs to the marketplace during the second quarter; three of which were our new ideal rigs. One rig was deployed in the Barnett Shale, one in Freestone County and the other one to East Texas to work in the Haynesville play. The other new rig was another of our highly-successful walking rigs that was deployed in the Rockies. Three of these four new rigs were activated late in the quarter, so they did not contribute much to our operating results. Since the end of the quarter, we have completed two additional ideal rigs, one working in the Haynesville play, and the other moving to the Barnett Shale this week.

To give you a complete update on our 2008 new build program, we now have a total of eight of the ideal rigs deployed in the field, and we are delighted with the performance of these rigs by every measurement. As mentioned previously, we expect the remaining seven rigs of our original 15 new build program will all be completed during the next six months. All remaining seven rigs have now been contracted and most of these rigs will be deployed in either the Barnett Shale, or the emerging Haynesville shale play of East Texas and North Louisiana. Today, we are also pleased to announce our plans to add 20 additional new build rigs, scheduled for deliveries in 2008 and continuing through early 2010.

Let me give you some details on these new orders. Six of the rigs are especially designed, fast moving, AC electric, thousand horsepower rigs designed for drilling horizontal wells in the Marcellus play of the Appalachians. All six of these rigs have been contracted on three-year terms with very favorable pricing. We anticipate all six of these rigs will be completed and delivered by the end of Q3 next year. As you know, we have had three of our existing rigs drilling horizontal wells in the Marcellus for well over 12 months now, and we feel we are extremely well positioned to meet the needs of the industry in this play. We expect that three more rigs from our existing fleet will be deployed in Appalachia prior to year end. Well positioned. In addition to these six new 1,000-horsepower rigs, we have also placed orders for six new 1500-horsepower rigs for delivery in 2009.

These rigs will be virtually the same as our previous 15 ideal rigs with one exception. The new rigs will all be AC as opposed to SCR electric. A couple of these rigs are already under contract. We have verbal commitments on a couple more and we expect to sign additional contracts in the very near future. These rigs will be ideally suited and highly desirable for the emerging Haynesville shale play.

In addition to these 12 new rigs, we are also constructing eight of our highly-successful walking rigs, and we have contracts in place for all of these. This technology has proven to be highly efficient in drilling from pads in various resource plays such as the Rockies and the Barnett Shale. We see growing momentum for this technology. With the construction of these additional eight walking rigs, we will have a total of 20 walking rigs in our fleet. Additional orders for these rigs are expected in the coming months. Over the last few years, we have significantly upgraded our drilling rig fleet with our industry leading walking rigs, all of the aforementioned new build rigs for both '08 and 2009, we will exit 2009 with a substantial fleet of new state of the art drilling rigs. In addition, we also have a large number of rigs that have been refurbished over the last three years. We feel our fleet is very well suited to meet expected future drilling activity, both with its increasing emphasis on unconventional plays as well as traditional infill drilling. We are well positioned to meet expected increases in rig demand with the deployment of our new rigs, our continuing rig upgrade programs and our existing idle capacity.

Turning now to do pressure pumping business I'd like to make a few comments about universal well services. As expected, business levels in our pressure pumping operations in Appalachia improved during the second quarter. Both the number of jobs completed and average revenue per job increased compared to the first quarter. Revenues for the second quarter 2008 were up 33% sequentially, and 10% higher than the same quarter a year ago. After a slow start to the quarter due to late winter weather conditions, our business rebounded nicely in May and June. The number of jobs was still down from the record quarters of 2007, and average revenue per job posted a new all time high during Q2. Revenues for the quarter were $57.1 million, and average revenue per job improved to $16,792. Operating margins are still being impacted by high fuel costs and high sand costs, two of these items are really the major expense items in this business.

In terms of capital we spent $18 million on new equipment during the quarter, with a large amount of that directed towards upgrading our fracturing capabilities. We have now taken delivery of two of our new 2250-horsepower quintiplex pumps, specifically purchased for horizontal fracs in the Marcellus shale. The remaining three quints are expected to be delivered by the end of August. We expect this additional equipment to drive significant growth for the balance of 2008 and in the coming years.

Turning now to the drilling fluid segment, Ambar Lone Star experienced a better quarter with revenues up over 18% sequentially. Lack of activity in the Gulf of Mexico is still hampering our operation and, of course, has impacted our revenues and earnings. Revenues year over year were down 2%, and this has been compounded by cost increases in barite, fuel and other raw materials. Obviously, these things have put even more pressure on margins. Due to these rising costs, we were able to institute a broad based price increase during the quarters and margins have improved somewhat in June. And with that, I will now turn the call back to Mark for some concluding remarks.

Thanks, Doug. As Doug's comments reflect, we saw a major step change in our drilling business in June and again in July with accelerating demand for both new and existing rigs. As we had discussed in prior conference calls we had expected this change based on strong commodity prices and in particular natural gas prices at $9 or higher, which started in late February.

I would now like to discuss and make a few observations about our expectations for the third quarter. As we see the current business environment, we expect, number one, our rig count for the third quarter will increase sequentially by approximately 30 rigs. Number two, in Q3 we expect our average margin per drilling day will increase by approximately $300 per day. And, number three, in Q3, we expect our pressure pumping revenue to increase sequentially by ten to 15%. Our customers' confidence in the long-term future of U.S. drilling has never been higher. We are seeing customers willing to sign multi-year contracts, reflecting their confidence both in the market for rigs in general and in the quality of our rigs and service in particular. Additionally, we are seeing strong demand by customers to activate additional rigs and the accelerating upward trend and movement in average revenue per day. We believe our strong balance sheet, our dividend and our commitment to invest in the rig fleet and pressure pumping business has and will continue to benefit our company and its shareholders in the future.

Before we open the call to questions, we would like to take this opportunity to express our sincere appreciation to our employees in each and every one of our business units for their dedication and hard work. Our financial results, our operating performance, and our safety improvements would not have been possible without their efforts. We are very excited about the future. Our people will continue to take a key role in our success. With that, Eric, we'll turn it over to questions. Thank you.

(OPERATOR INSTRUCTIONS). Your first question comes from the line of John Fitzgerald with Raymond James.

Good morning, guys. A couple of questions on your stacked fleet. Can you give a ballpark number as to how much cash you have to put into a stacked rig before you bring it back into service?

John, that really varies rig by rig. We have, of the current 60 some stacked rigs we have today, probably half of them could go back to work tomorrow with little or no capital expenditures. There is always some incremental operating expenditures that you face when you reactivate a rig. But in terms of capital, about half the stack fleet could go back to work with very little capital. The remaining rigs in that would, could vary anywhere from as little as $100,000 to upwards of a couple million dollars before we put them back to work.

Okay. And I guess out of the 60 or so you said could you put our near term, are those weighted in a certain region or by a certain depth capacity.

There probably is. That's a good question to. Give you some idea, about 40 of those rigs are 750-horsepower rigs and under, about another 20 or so are 750 to 1,000. So that's the bulk of the stacked rigs. We do have four of the much larger rigs, the 2000-horsepower rigs that are also stacked. But at the moment we think those will go back to work in the short term. In terms of regions, those, the smaller rigs are primarily in west Texas and the Rockies are probably the two big areas where those rigs reside.

I guess switching over to the margin side, the cost increase was a little bit more than we expected in second quarter. Is that kind of baked into the $300 margin increased you are going to see next quarter and is that a labor issue, a fuel issue and something you kind of see going forward or is that a one time deal?

It is considering the comments about margin going forward. There's a couple of aspects to it, the most significant of which is when we are activating rigs you have to hire people and you have to prepare the rig before you ever earn any revenue. And that was a couple hundred dollars worth of increase and cost per day in the second quarter, and with the activation of rigs you can see in July we expect that to continue. There is also an increase in repair costs and costs of operating rigs over the last 12 months.

John, let me add a point to that. We expect to see another ten or 15 of those currently stacked rigs go back to work here in the next quarter or two. We have work for them. And I think we feel there will be some additional start up costs for those rigs to go back to work as well.

Okay. Guys. Great. Thanks for the call.

Your next question comes from the line of Geoff Kieburtz with Weeden, please proceed.

Really kind of following I was all the same thing. With the plans you have for adding new rigs should we really think about this $200 per day as sort of going to continue going forward as a cost or is that also inflating?

Geoff, I think if we look at other up cycles what you find is initially there's a bump in average cost per day and then as we run more rigs on a per day basis our costs then begin to decline because you get past that point of having people activating rigs and get to more stable rig count.

I'm sorry, just -- with the plans that Doug outlined before that doesn't seem like that slowing as the rate of additions is going to curve until maybe the end of '09. Is that right?

Unclear, you mentioned 15 rigs and the question is how many really go out of the next couple of quarters, it could be more than that. If that were the case then that couple hundred dollars would stay in it as the rig counts begin to stabilize those costs could drop back down. The other side of it though there is inflation in the sense that we are having a lot of demands on people in the oil field which has created a bit of a higher cost environment than we've seen in the past. So that's a factor that would go the other way and potentially could keep the cost of these levels going forward.

Do you have a ballpark estimate of what that underlying inflation is excluding the specific start up cost?

Well, we know there are welders are more expensive, people that service the rigs are more expensive than they were a couple of years ago, there's a lot of demands on their timing exactly what it is I don't know. One observation to make, there's two things going on relative to rig count. One is we are activating the new rigs that we we announced back in 2006 we also added to that program. Those rigs I think have a very small impact from a cost per day point of view because you're constructing a new rig and when it's constructed and rigged up it goes directly to the field and it's moved in you're generally collecting revenue at the moment of activation.

The place you incur the extra cost is where a rig has been stacked for more than a couple of months and in that time there's parts within that rig not capital parts, they are expendable that need to be replaced. You also have to hire a new crews because with don't keep the rigs around when they are stacked. You have to train them. They have to learn how to rig up the rig, et cetera. The extra cost per day is about reactivation and not about the new build program.

I appreciate you can't maybe pinpoint the inflation rate but would you put it above or below 10%?

I would have to say at the moment it would be well below 10%. But as this industry heats up, Geoff, who knows where that will be? If we were running more industry than we have in a long, long time and there is increasing demands on that almost every facet of the service business from labor to welders to repair and supply costs. So at the moment I think we've kept a pretty good lid on it but we are starting to see some signs of creeping inflation.

I would add to that also keep in mind that in excess of 50% of our operating costs is payroll driven which for the most part is a pass through to customers under our contracts. And what we've seen of late is the increasing in cost per day has been driven by this start up cost and then also in the repairs and maintenance side for that, call it 35 or 40% of our costs that are not payroll driven.

So that under 10% and a fair portion of that can be passed through immediately or within a quarter.

Yes.

And on the pressure pumping side, would you say the same thing, under 10% inflation?

Yes, yes, I think I would, Geoff.

And last question, can you give us a sense of what the leading edge rate is today for, say, each of 1,000-horsepower and a 1500-horsepower rig?

We don't typically divulge those numbers, Geoff, so I prefer not to get into that. But certainly pricing has moved pretty dramatically in the last 30 to 45 days and in the areas where, for example, 1,000 to 1500-horsepower rigs there just aren't any of them available today. Obviously the prices have moved more quickly until those rigs than others.

Jiff, we think the better indicator is average revenue per day. That's why we talk about it. Because otherwise you start to speak about in effect one rig and it's about as misleading about a portfolio manager talking about one stock.

Got you. Thank you.

Your next question comes from the line of Doug Becker with Banc of America Securities. Please proceed.

Thanks. Doug, you mentioned some favorable economics in the new builds, just hoping to get a little more color on that, whether it's a day rate or pay back rig that you're specking.

Maybe I will take that question, Doug, Mark Siegel. Frankly we wouldn't be building new builds if we didn't think the economics were favorable. We always talked about entering into long term contracts and doing things as sort of a customer driven organization. Here we see our customers having demand for a certain kind of rig and our ability to provide it. We are very proud of the fact that over the last five years our average return on equity has been 24%. We think that's among the industry leaders. When we make these decisions to invest in new build rigs we think that we are going to continue to generate the kinds of returns for shareholder that is we historically have generated. Otherwise we wouldn't be doing it. So I guess I'm trying to tell you in a long winded way that we don't want to get into the specifics of the economics of each transaction we think that doesn't do our company and its shareholders a lot of good, but we think that we are achieving rates of return consistent with historical rates of return.

Let me ask it this way. Are you getting a lower pay back than you were maybe in the past?

I don't believe we are getting a different pay back. We are getting a consistent pay back.

Fair enough. Obviously demand has been picking up pretty aggressively. Are there any opportunities or I guess customer inquiries that you haven't been able to meet because of crew constraints?

There's been a little bit of that in certain markets, at least on a temporary situation. Obviously if a customer phones today and wants to fire up a rig tomorrow we can't always meat what they are requiring. But for the most part, other than the unavailability of 1,000 and 1500-horsepower rigs we really haven't had to turn away customers.

And that leads into a question about the 740-horsepower rigs and below. Given the demand trends that you're seeing, what's the prospect of those being reactivated?

Well, the interesting thing is that since I've been here, Doug, I've heard repeatedly that those rigs would never go back to work. And it's interesting the first six months of this year we put 25 or 30 of those rigs back to work in the six months already. We have another ten or 15 that are probably going to go back to work by the end of the year. So I think there's a significant number of them that still are prospects and they will work.

It's definitely encouraging. Just briefly you had mentioned previously on the last quarter that North Texas and Rockies had been relatively weak compared to some of the other regions. Has that reversed and are there other regions right now that are maybe not growing as fast as others?

I think both north Texas and Rockies were at a point in time there was some weakness there. We've actually seen virtually all of our regions improve pretty dramatically. If there is one area that's a little more spotty than the rest it could be west Texas.

Okay. Thank you very much.

I would add one thing to that, what we have really seen is a significant demand for this, and Doug was really speaking about this, this return of existing rigs from our fleet as well as for the new rigs and in various different horsepower ratings.

Okay. Thanks, Mark.

Your next question comes from the line of Dan Boyd with Goldman Sachs. Please proceed.

Hi, thanks. I know you don't like to talk about specific, where leading edge day rates are moving but can you give us some color on where average day rates in your fleet for the 1,000, 1500-horsepower class relative to the fleet average?

I don't know, I think we've ever divulged or tried to do that to sort of take out a particular class and say, okay, we are getting this kind of average rate for this particular sort of set of rigs. And, frankly, the reason is because I think it would be quite misleading. We do business as you know across many basins in North America and prices vary among basins and they vary also depending on what in effect the contractor is furnishing, et cetera. So I think that that information is not something we generally give because we don't think there's a way to capsulate it in a way that's terribly meaningful.

Your new build program some of the deliveries seem like they are going into 2010, does that imply that you wouldn't be able to get additional rigs delivered in 2009 or is that not the case?

No, we still certainly have some capacity to deliver some additional rigs in 2009. I'm not going to share with you just how much but at the moment I would be real surprised if we don't have some further announcements for rigs to be delivered later in 2009. But at the moment with what we've announced pretty much takes us through to about the end of Q2 next year, and maybe into Q3. So we do have some additional capacity for later in the year next year.

Okay. How do you think about your internal capacity to deliver rigs I guess maybe on a per month basis?

Well, we have a lot of capacity in terms of rig building. Let me share with you. We primarily with our new build rigs, that we purchased the complete rig from a particular supplier, we by components and we basically rig those rigs up in two of our rig up yards, one in Tyler and one in Victoria. All of our walking rigs are built in our Midland yard in west Texas, we have other capabilities around the company to add capacity if we needed to. But we are trying to do things prudently to make sure that we maintain a handle on our costs. And it's also very important to make sure that we spend the appropriate time to introduce rigs to the marketplaces in a very controlled, prudent Fax so that they go to work with little or no problems.

One last question, you mentioned I think you have 64 sort of idle or stacked rigs at the moment. That sort of at the peak of the market you had over 100 idle or stacked, and maybe that calculation is wrong, but and then implying that you put maybe 30 back to work, does that suggest that you did scrap a few or take those out of what you would consider a marketed fleet?

I think we may have ignored Canada in that set of numbers with us running 20 rigs in Canada and I think Doug was speaking to U.S. numbers of stacked rigs. So that's another ten in Canada may reconcile that for you.

That makes sense. Okay. Thanks, guys.

And, no, we have not scrapped any rigs.

350 approximately rigs we've talked about.

Your next question come from the line of Mike Drickamer with Morgan Keegan. Please proceed.

With you guys taking in and orders some rigs here, what lead times are you being quoted for new rig delivery at this point?

Most of the lead times are in the nine to twelve-month time frame. I think as you know we had a significant amount of inventory that we had purchased back in '06 and '07. We were able to put some new rigs together just based on our inventory. Anything new we are ordering today, we are looking at nine to 12 months.

What bottlenecks are being seen right now for the new build rigs?

Like I say, the big bottleneck is just getting the equipment component deliveries from our suppliers?

Mike, one thing I think it's worth add to go what Doug said is that part of the reason that we are able to get the equipment in the times that Doug spoke about is that we have been in discussions about with suppliers and in the supply chain for a long time and are a major customer.

So perhaps if you were a smaller mom and pop contractor it would take longer than the nine to 12 months then for the new rig?

I would think so and that's really what I was trying to indicate, was that in effect I don't think that those availabilities are availabilities for everyone who would want to go buy a rig today.

And then what kind of cost inflation have we seen in the cost of building or buying these new rigs?

I think the cost inflation has been a little bit but it's probably under 5%. Probably the biggest difference with us from the rigs we ordered in 2006 versus the rigs we are ordering today is actually the fact that we are going AC as opposed to SCR and that's added probably $1 million per rig to the cost but that was something that we made that decision and decided that's the right way to go. But cost inflation overall is probably in that 5% range.

Then one more on the idle rigs. You discussed how a number of those rigs could go back with minimal capital being invested in the rigs. What is your capacity, though, as far as being able to bring those back as far as crewing them up and I guess supplying the pipe and also else that would be needed for those rigs, one, two, a month or is it higher than that?

I think it's higher than that. I think we could probably put out and I am going to hazard a guess here, we probably could put out five a month. Again, we are trying to do it prudently. We are not going to put a rig out and do a bad job for a customer. We want to be sure that we put out quality crews. We want to make sure the rig is ready to go to work.

In previous calls the industry has talked about labor and how much of a bottle neck labor was. That seems to be less of an issue this earnings season. Am I reading that wrong or is something else going on here.

I'm not sure you're reading it wrong. I think people are not talking about it very much. I think labor is going to be a huge challenge in the industry in the next two, three years if it isn't already today. I think so far we've been able to gets the incremental rigs in the marketplace with little or no problems but I think we are going to see increasing demands for those kind of skill sets throughout the industry. So I think as an industry we are going to have to do more things in terms of recruiting and training and onboarding people and getting people that get attracted to this business. One other comment I didn't mention you asked about drill pipe, reactivating the rigs, with us drill pipe is not a problem whatsoever. We have plenty of drill pipe to reactivate all the rigs we want to.

All right. Thanks a lot, gentlemen. That's all for me.

Your next question comes from the line of Alan Laws with Merrill Lynch.

Good morning. I got a couple of follow-ups, actually, more than anything. On the 20 new ones that you're building you talked about the cost inflation there just previously. How much are these rigs costing now?

Alan, on average they are going to be about $17 million.

And these are A.C. with top drivers and everything else on them.

Top drivers, hydraulic cat walks, states of the art anything you could put on the rig that a customer would want. Some of them include air packages for rigs in the Northeast.

So that, you said 17.5.

About 17.

17, and that's excluding drill pipe.

That includes drill pipe.

Zero, good, all right. And of the 20, it look like you have contracts for most of them. You didn't mention any contracts for the eight walking rigs that you were constructing?

Actually I thought I did. They are all contracted.

All contracted. Okay. I missed that.

I'm sorry, but, no, all eight of those walking rigs are contracted and I don't think that these -- these rigs are state-of-the-art second to none.

These are obviously the walk in, stock in?

That's the last 8. The other 12 are not walking rigs.

Okay. Okay. Got that. On your reactivations you had 60 stacks, neighbors had similar number, they thought that only 20 of theirs would ever go back to work. You have 30 that could go back. Could you say something about the size of these rigs and their configurations and how many you expect to go back other than the ten to 15 you already mentioned here.

As I mentioned the ten or 15 we already know at some point in time are going to go back to work in the neck couple of months. As I mentioned the ten or 15 we already know at some point in time are going to go back to work in the next couple of months. We certainly haven't seen much interest in the 500-horsepower and less. So I think most of the rigs that you'll see go back to work are in that 750-horsepower category.

These have top drives on them?

No.

Would you put that on? Does that make them more.

Some of them you might be able to, Alan but with that small a rig it's difficult to get a top drive that will fit in the mast. You can rent some top drives that will fit but typically they tend to be the smaller top drives with more limited capability.

And last thing I got here is on universal. Can you remind me how many spreads you guys run and how much horsepower in the whole company?

Well, we don't normally talk about the spreads or horsepower. We have, I think I mentioned to you a couple conference calls ago that we will end or exit 2008 with about 110,000-horsepower fracing capability. I don't have the numbers in front of me for nitrogen and cementing and some of the other things. But we have, this year we will have a full frac crew available using these quintiplex pumps for doing the horizontal shale fracs and we have plans to add to that going forward.

That's all I have.

Next question comes from the line of Jeff Tillery, with Tudor Pickering.

Good morning.

The name got slaughtered a bit?

It's all right. The choice to go with AC, what drives that? Is it just comfort level with the technology in the up time?

Jeff, AC technology has been in the lands business now for a couple of years. We were not a first mover to A.C. technology because we wanted to make sure that the bugs got out of the system and that the technology is as described. We have seen some real recent improvements particularly with our supplier and what they do with both offshore and what they are proposing to do with lands rigs. And the prime benefits really are the control from the driller's perspective to get far more control of the operations, what they see. Obviously the other big benefit to them is the size and the weight of the components. And the fuel consumption. Those are probably the three big things that we see are advantages to AC over SCR. Having said that, SCR technology has been around for 30 some years, highly proven, very effective. But we do feel it's time for to us stick our toe in the water and see just how good the AC technology can be for us.

And on, as far as your CapEx budget, do these new builds, are they incremental to the 485 you guys have talked about in the past? And can you give us a little bit of guidance on what you're looking at for 2009, just what the new builds announced today?

For 2008 the new builds are going to add a little bit to our CapEx for 2008 and we would guess at this point that it would be about $530 million. Related to those new builds, about $350 million is committed for 2009 or will be committed for 2009. In terms of a complete CapEx budget for 2009 that has not yet been completed.

That's helpful, though. My last question is regarding some of these smaller rigs that are left in the idle fleet. You guys have talked a little bit in the past about the potential opportunity to move some of them up to the Northeast. Could you just give us an update on how you're thinking about that right now?

Interestingly enough we thought quite a few of those rigs would be certainly suitable and very capable of drilling a lot of the wells in the Appalachians. I think what has surprised us a lists is our customers interest in actually having new rigs. I think the new rigs that we announced we had initially thought we would probably put some of these lower horsepower rigs to work up in that marketplace but the customers have actually moved us in a different direction.

All right. Thank you very much.

Your next question comes from the line of John Daniels with Simmons and Company. Please proceed.

Hi, guys, quick question on your pumping business, it looks like had you a nice IBM crease in your revenue your job. Is it safe to say that's more business mix as opposed to price increases?

No, it's actually price increases and us being pretty selective in terms of jobs we've taken in that market.

And on the jobs that you're doing right now, what would you say, is it 20,000-horsepower per frac job right now?

No, actually we haven't done any of the deep horizontal fracs yet to date. We hope sometime in this quarter we hope to have done a couple of them. Today, all the fracing work has been the traditional once where you have 2000 or 2500-horsepower on a location.

Last question, any opportunity to expand beyond Appalachia on the pumping side?

That's something we look at the all the time and at the moment, we feel we have a niche market there. We are local. We have a very good reputation in the local market. Not to say we won't be expanding out, but at the moment, there appears to be plenty of capacity in the industry with all our major competitors. So unless we feel a niche somewhere where we feel we can bring something to the market with will probably stick to our knitting in the Appalachians.

That's it.

Next question, Kurt Hallead with RBC Capital Markets. Please proceed.

Good morning. I think by now you guys are aware of the skepticism in the market about Patterson's ability to effectively compete with the new rigs and you've addressed that with some of your announcements here today and at the beginning of the year. Just wonder if you guys can provide some color because some of the push back now is that essentially the bulk of the market share gain is going to go to one of your primary competitors and it's not Neighbors. So can you address how you guys are going to stack up with respect to adding new rigs into the market as required going forward, vis-a-vis the rest of the industry?

Sure, Kurt. Let me take a shot eight the and if John and Doug want to add to it, that would be fine. I think we see the building of new rigs and again, this was the same thing we said before about long-term contracts as being highly customer driven. And that's basically what Doug was saying before. We try to offer our customers in effect the opportunity for the right rig at the right price for the right drilling job. And if they want an existing rig, that's great. If they want a new rig, that's great. And that's really how we see it. And in fact obviously from the number of rigs that we are currently running, you get a strong sense that our existing rig fleet does in fact compete very, very well with other competitors' rigs. Our walking rigs we believe to be absolutely state-of-the-art and compete with other people's state-of-the-art rigs. We think mano y mano.

So we don't see it as some kind of need to do this to catch up. We are doing this in response to our customers and that's the basis for it. And, finally, as respects the question that I think is sort of behind your question about if one of our competitors decides to build X rigs, we don't feel the need to build X plus one rigs. For purposes of some kind of race to in effect show the investors that we can build the same number of rigs as one of our competitors. Fundamentally, our response to building rigs is one which as I said emanates from the customer, and in response to the customer and does so in a way that we think is also responsive to our investors' expectations about a great return on equity.

I understand and I guess the question I had is I noticed that just periods in a lot of new rigs have contracts behind them and whether or not there is going to be a shift in share of those contracts going forward, whether or not you would be able to maintain your current position in the market or is there some other dynamic out there that is causing a shift in share of incremental business going forward.

Kurt, I think we are getting our share of the market. I think we've always gotten our share of the market. I think that what we have been is very price disciplined as a company over a lot of years and in an up market we've always expanded faster than our competitors because we've had the capacity to do so. We've always also seen the fastest increases typically in average margin per day. So we've both gotten utilization as well as increases in margin. What we haven't done I think is in effect try to maintain percentages of market and market share just for the sake of doing so in, sometimes in down markets and have been in fact willing to accept a lower share of market in down markets. But that's never been the case in up markets.

Okay. So we've had natural gas prices come off of 13 back to 9. Just as it's kind of getting off the grounds here, what indications are you getting from customers, what are their price sensitivities? Is $9 the marker? Is it $8? Is it $7? What's the sensitivity points where everybody starts blowing their horns again?

Kurt, we've seen the pricing change obviously of natural gas in the natural gas market but we've seen nothing to indicate that there's been any diminution of interest on the part of our customers. In fact in the kind of prepared remarks that I made at the end, those remarks about the customer's willingness to enter into and desire to enter into these long-term contracts really reflects their bullishness I think about the industry generally. And that's really the point I was trying to make which is that their bullishness is right up until today, we haven't seen any signs irrespective of the fact that gas has obviously come down. That's point one. Point two is our remarks have always been going back to February that kind of looking at the market as sort of $9 or better that for kind of a prolonged period has been what we think our customers were hoping for and expected and was driving their activity. If it's significantly below that on a long-term basis, we won be surprised to see some short term issue.

How would you compare and contrast what's going on now versus January of '06 because the fundamentals in the land business were very good in January of '06, even, and gas prices were coming down, and everybody started getting nervous and lo and behold, six months, nine months later everybody started pulling in their horns. Could you give a little compare and contrast to that period?

Kurt, I don't think I can because fundamentally the question is what's going on with the commodity price. And, I don't know that I can perfectly recollect January of '06 at this moment, but the question is, if we have $126 oil prices and $9.25 gas prices and we kind of sustained levels in this area, I think everything is going to be great. If it changes dramatically from here obviously people will rethink what's going on. But I think this has been historically very, very good set of pricing that currently exists in the marketplace so we are feeling -- our customers are quite bullish.

Great. Thanks.

Your next question comes from the line of Daniel Kramer with Colt Asset Management. Please proceed. Mr. Kramer, your line is open. You may be on mute. Your next question comes from the line of Arun Jayaram with Credit Suisse.

A quick question for you guys. If the rig count was to increase by 200 rigs from today's levels, based on your conversation with operators, how many rigs of those do you think would be existing rigs in the field and how many of those do you think would be new builds?

Arun, over what period of time did you say the rig increase?

Let's just say over the next six to nine months.

I think in the short term if the short term is the six-month period, I would say a lot of those rigs are going to have to come out of the existing idle capacity in the industry. And I think that plays very well into our hands. If it's a longer period obviously some of these new builds that people have announced as well as us will start to play a major role in that. But I think in the short term, a lot of it has to come from the current capacity.

Second, I was wondering if you could comment on what you are seeing in Canada in terms of pricing and forward-looking demand.

We think the Canadian count is probably going to stay in a fairly narrow band similar to what you've seen in the last month or so. I think as the weather is good over the course of the summer I think the rig count may go up potentially 100 rigs up there. Typically once you get into September, October, November, you get some sloppy weather that can have some fairly large fluctuations. I think generally Canada probably will be slightly better than what you've seen, but we don't see a big run away up there. In our own case, we expect ten to 11 rigs to be running probably through up until freeze up.

Last question is you talked about the 20 incremental type of new builds. Any help in terms of what do you think the ultimate earnings power of those rigs could be on an annual basis when the rigs are up and running in 2010?

I think we would be hesitant to project what the expected earnings for those 20 rigs would be.

Or could you help us, remind us in terms of depreciation, John, how are you going to depreciate those rigs, is it 15 years, 10% salvage?

We we actually depreciate all our equipment with no salvage value and we do it without component the but the weighted-average life for for a rig is in the 12 to fourteen-year range. An average if you use 13 years you should get a pretty accurate answer.

That's helpful.

Next question, Amanda Scott with [Morales, Sigbert & Company]. Please proceed.

Hi, guys. I was wondering if you can please provide me with a breakdown of the none of rigs that Patterson owns that are capable of directional drilling?

That's kind of a very difficult question to answer. Virtually all of them could drill some type of a directional well. There's many, many different kinds of directional wells and horizontal wells. As I said I have to say that virtually all of them could drill a directional well but to drill a deep horizontal well you start factoring in a number of other things that potentially, three quarters of our rigs could only drill certain types of deep horizontal wells.

That's really helpful. I know that's a big question and I have a couple more. On the Q1 call it was mentioned that Patterson has three rigs in Appalachia that are currently, and would have an additional three by the end of '08. Do you have any plans to increase the rig count there and field support services as well in the Marcellus play specifically?

I mentioned all of those six new rigs are going up to the Appalachians in '09 and we do expect some additional existing equipment to go to that market throughout 2009. So obviously with that, with that kind of an operation we are looking at building up our infrastructure up there for the drilling company. We do have a leg up I think in that our sister company, Universal has been established in that marketplace for over 30 years and so we do rely a little bit on our little brother up there to help us with some of these things.

What about the Bakken formation, same thing there or are you not seeing as much demand there?

The Bakken is a very interesting play. We've moved a number of rigs up in there in the last three to four months. I think you will see continuing rigs go into that marketplace over the course of the next six months. We have several I think at the moment that are probably heading to that marketplace. But again it takes a very specific type of rig to drill those wells.

Right. Okay. Well, thank you very much for your time. I appreciate it.

Thank you.

Your next question comes from the line of Todd Garman with Peters & Co.

Good morning, I just want to come back to your pressure pumping business for a minute. You mentioned had you higher sand costs here during the quarter. Can you give us some color on why that was.

Sand costs primarily we have seen some pressure obviously on getting certain qualities of sands. We have seen some price inflation. We do have contracts with two or three suppliers in the market. But it's interesting, some of our competitors are actually having to truck sand in from the western U.S. for that marketplace. So we have seen some pressure on sands pricing. And the grades and qualities of sand required for these horizontal fracs is certainly different than the standard frac.

So how do you think you are positioned with your sand suppliers to have enough supply of going forward to meet the forecast demand in that play?

Well, our guys certainly talk to our suppliers all the time. We think we are in pretty good shape. It will depends just how quickly that market turns up and heats up. We think we certainly have the capability of doing two of those deep horizontal fracs every month and we are geared up for about that level.

And is that in addition to the conventional fracturing business that you currently have or is that total?

No, that's in addition to.

Okay. Thank you.

There are no more audio questions at this time.

Well, we'd like to thank all of our investors and the analyst community for joining us on this call and look forward to speaking with you again at the end of our third quarter. Thanks everybody.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a good day.