Patterson-UTI Energy Inc (PTEN) 2008 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first quarter 2008 Patterson-UTI Energy Incorporated earnings conference call. My name is Jasmine, and I will be your operator for today. At this time, all attendees are in listen-only mode. We conduct a question-and-answer session towards the end of this conference. (OPERATOR INSTRUCTIONS). On behalf of Patterson-UTI Energy, I introduce Mr. Geoff Lloyd. You may proceed sir.

Thank you very much. Good morning. On behalf of Patterson-UTI Energy, I would like to welcome you to today's conference call to discuss the results of the three months ended March 31, 2008. Participating in the 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 which state the company's or management's intentions, beliefs, 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 declines in oil and natural gas prices that could adversely affect demand for the company's services and their associated effect on day rates, rig utilization and planned capital expenditures. Excess availability of land drilling rigs, including as after the reactivation of new land drilling rigs, adverse industry conditions, difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment and the 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 SEC's EDGAR system. The company undertakes no obligation to publicly update or revise any forward-looking statements. And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thank you, Geoff, good morning and thank you for joining us today. I hope that by now all of have you had an opportunity to read our earnings release, which was issued earlier this morning prior to the opening of the market. I would now like to review the results of of the three months ended March 31, 2008 and to indicate some of the financial highlights from the just completed quarter. I will then turn the call over to Doug Wall, who will make some brief comments on the results of the individual operating units. As always, we will be pleased to take your questions following these remarks.

To summarize, net income for the three month period totaled $77.4 million, or $0.50 per share, compared to $116 million or $0.73 per share for the three months ended March 31, 2007. Revenues for the just completed quarter were $505 million, compared to $547 million for the first quarter of 2007. We also announced this morning that the board has approved an increase in the quarterly cash dividend to $0.16 per share from $0.12 per share. This represents the fourth consecutive yearly increase, bringing the current annual dividend yield to 2.3%, based on yesterday's closing price. This 33% increase in our dividend reflects our company's confidence in its future cash flow, and continued commitment to return capital to our shareholders. The quarterly dividend will be paid on June 27, 2008 to shareholders of record as of June 12th, 2008.

Before turning the call over to Doug and before giving our expectations for the second quarter, I would like to make four key summary points. First, in late February, shortly after our last conference call, we saw natural gas prices rise above $9 and prices have remained comfortably above $9 since then. We believe that these prices will encourage our customers to drill more wells, and in turn, this will cause additional rigs to be activated. Number two, during the last two months, we have seen an increase in the number of our rigs operating in the U.S. and we expect our rig count will continue to increase over the rest of the year, as long as natural gas prices remain at these levels. Number three, very recently, we have seen pricing for U.S. rigs starting to increase at a modest rate. Number four, our substantial rig upgrade program now into its fourth year has well-positioned us to meet our customers' needs for rigs, especially rigs for the unconventional resource plays.

I would now like to turn the call over to Doug, who will review the results from our operating units for the quarter.

Thank you, Mark.

I would like to make a few brief comments on each one of the operating divisions and I will start with the drilling company. For the quarter ended March 31st, 2008, the company had an average of 244 rigs operating, including 232 rigs in the U.S., and 12 rigs in Canada. This compares to average of 241 rigs operating in the fourth quarter. The breakdown there was 231 rigs in the U.S. and 10 in Canada. This represents the third straight quarter of a relatively stable rig count, with some obvious minor changes in the mix between the U.S. and Canada. I would like to point out that the positive trend in the U.S., where we have averaged 229 rigs in January, 230 in February, and 237 rigs working in March.

Average revenues per operating day during the first quarter were $18,900, compared to $19,250 in the fourth quarter. This does include the impact of several term commitments that expired during the first quarter. For the most part, these rigs continued to work but at market rates. Average direct operating costs per day were $10,990 for the quarter, down slightly from the $11,110 for the fourth quarter. Our overall gross margins declined by $230 per day from Q4. At the end of the quarter, we had 38 rigs working under contracts which had an original term of more than one year. Therefore, with only 15% of our operating rigs on term contracts, we are well positioned to benefit from any improvement in spot rig rates. During the quarter, we experienced some increased utilization in subTexas and the Permian, unfortunately we saw some declines in north Texas and the Rockies.

I would like to mention a couple of operational highlights for the first quarter. We introduced two new ideal rigs to the market place in Q1, both of them in February, one in south Texas and the other in the Barnett Shale. By quarter end, we had a total of three of these new rigs deployed in the field, and to date, we are extremely pleased with the performance of the rigs. As we have mentioned previously, these rigs are our new generation, 1500-horsepower rigs. They are fast moving, 18,000 depth capacity. They incorporate state-of-the-art EDS systems, top drives and numerous other automated pipe paneling features. Rig 205 in the Barnett Shale has now drilled three wells, and remarkably is averaging approximately 48 hours on moves between locations. Since the end of the quarter, we have completed two more of these rigs and they are now spudded on their first wells. One of these rigs is from East Texas and the other is in the Barnett Shale. We are currently rigging up the next three rigs and expect that the remaining seven rigs of our original 15 rig new build program will all be completed during calendar 2008. Over the last few years, we have significantly upgraded our drilling rig fleet, including the deployment of approximately 75 new and like= new rigs. Our fleet is well suited to meet expected future drilling activity, with its increasing emphasis on unconventional resource plays. We feel we are well positioned to meet expected increases in rig demand, with the deployment of our remaining new rigs, our continuing rig upgrade program, and our existing idle capacity.

I would now like to turn to our pressure pumping business. Universal Well Services, which as you know has achieved record growth during the four quarters of 2007. Although revenues for the first quarter of 2008 were up 11% compared to last year, this was below our expectation. Highly fluctuating winter weather in the northeast played havoc with our operations in Q1, as operators struggled with poor road and location conditions. March was a particularly poor month, as alternating spring and winter weather created extremely wet and muddy working conditions. As a consequence, the number of jobs completed in Q1 declined almost 20% from activity levels of Q4. The good news is that most of this work has just been delayed, not canceled.

Revenues for the quarter were $42.9 million, and our average revenue per job declined slightly to $14,720. Our operating margins were greatly impacted by these weather delays as we had staffed up for much higher activity levels. Our head count is up over 25% year-over-year in anticipation of the higher activity levels we expect to see from the Marcellus shale play. In terms of capital, we spent $13 million on new equipment during the quarter, with a large amount of that directed towards upgrading our fracturing capabilities. We expect this additional equipment to drive significant growth for the balance of 2008, and in coming years. One of the operational highlights for the quarter was the deployment of our people and equipment in excess of 15 shale fracs for a variety of our customers. We are also very pleased with the performance of Eastern Reservoir Services, which is our well testing division, where we specialize in flowing back wells after these massive stimulations. We expect this growth to continue in both the Rockies and the Appalachian basin.

Turning now to the drilling fluids segment, Ambar Lone Star witnessed a slight improvement for the quarter with revenues up 7% sequentially. Lack of demand in the Gulf of Mexico is still hampering our operations, and of course has impacted our revenues and earnings. Revenues year-over-year were up almost 6%, however, cost increases in barite, fuel, and other raw materials have put even more pressure on our margins. With that, I will now turn the call back to Mark.

Thank you, Doug. I would now like to discuss and to make a few observations about our expectations for the second quarter. As we see the current business environment, we expect, first, our U.S. rig count for the second quarter will further increase by approximately 10 rigs to 242 rigs, with our overall rig count for the second quarter being essentially flat with the first quarter at 244 rigs, with increases in the U.S. overcoming declines in Canada. Second, in Q2, we expect that U.S. average revenue per day will remain essentially flat from the first to the second quarter, at approximately $18,600, with an overall decrease in average revenue per day of approximately $300 due to the falloff in Canadian activity. We expect costs to remain approximately $11,000 per day. Third, in Q2, we expect our operating margins at Universal Well Services to return to the levels seen in Q4.

We believe our strong balance sheet, our dividend, and our commitment to invest in the rig fleet and our 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 the employees in each 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 play a key role in our success.

At this point, I would like to open the call for questions.

(OPERATOR INSTRUCTIONS). And your first question comes from Mike Urban. You may proceed, sir.

Thanks, good morning. You said that you are seeing some moderate price increases in the U.S. land business so far. There's a view out there that given that you still have -- just the industry has a reasonable amount of stack capacity out there, that pricing gains may be hard to come by or take a while. Is there anything out there that can change that view, in other words, for instance the stack is held between you and Neighbors and then crews potentially initiating. I just wanted to think through the market dynamic as the market tightens up here.

Let me start and throw to to Doug second. There is, as you correctly point out the idle capacity is held by Patterson and by Neighbors that we believe, at least most of it. So there is a relatively limited supply of this idle capacity. More importantly, the capacity to do the kinds of work that our customers require is not in substantial excess capacity. That's relatively limited in capacity, and we think that our customers are starting to see as they went to increase their drilling programs, a shortage of the kind of equipment that they want to use and we believe that we are fortunate to have that equipment and to be able to meet that demand, but there's not so much of it available that we think that -- well, the relative shortage of what's available we think is going to push prices up. Doug?

Mike, I think we are certainly having different conversations with a lot of our customers today than we were having 30 and 45 days ago. We've started to see some signs of some price increases in certain markets and with certain kind of equipment. I think operators realize that prices may be on the way back up, and certainly some of them are already starting to ask about term contracts. We're having those conversations, but we're being very careful in the market place today.

Okay. Great. And --

On the people side -- I know you asked about the people. I certainly think that the number of rigs that go back to work from the idle capacity probably is going to be governed somewhat by the number of people. I think if rigs go back in an orderly fashion over some period of time, we and the industry will be able to manage it accordingly. But I think it would be difficult to put huge number of rigs together next week.

Okay. And you also mentioned that you had some strong markets but one area where you were down sequentially was in the Rockies. Do you see that as primarily seasonal and would that be one of the areas where you would expect activity to pick up through the year?

Yes, I do. I think the little bit of sloppiness that we saw in the Rockies really was a seasonal issue. Certainly the Farmington and the Hobbs area have been a little bit more challenging markets but the traditional Rockies markets we think will strengthen throughout the rest of the year.

Thank you.

Your next question comes from Alan Laws. You may proceed.

Thank you.

Good morning, Alan.

First on the 15 rig packages you have for NOV. You have one active that I think in the last quarter, you said you were going assemble two more and I didn't quite understand what you said there with your plans for the rest of the year for the other packages.

Okay, Alan, let me try to clarify that. During the quarter, we completed an additional two. So that at the end of the quarter, we have three out in the field working. Within two weeks, or with -- actually within the last two weeks, an additional two have gone out. So today we have five of those rigs in the field operating. We are currently rigging up three more to get the total days, and there's an additional seven rigs that we expect to have completed by year end.

Okay. Are these going out just on the spot market. Are you getting term contracts for these.

We primarily have been putting them into the spot market.

And how are they doing in terms the rate versus your other rigs?

Well, they are -- I guess what I will take, say, I will not give you the number, but they are on an equivalent basis given the fact that they have top drives, they have EDS systems. They are state-of-the-art. There's certainly a premium that we get for these rigs.

Would they be among your sort of top margin rigs out there today?

Yes, they would.

Okay. Second question was on the seasonal slide in the Rockies like everyone else has sort of had. A lot of snow up here. Can you talk about what your expectations for the pace of recovery? We are at record rig counts now and we haven't seen the Rockies move. Our expectation was it would surge a lot after the snow was gone. What is your expectation by how many rigs you will have active by the end of the third quarter.

In the Rockies?

Yes.

I'm not sure I can share that number with you. We saw some sloppiness in the first quarter that we think will correct itself. I don't know how many additional rigs will end up working in the Rockies. Certainly the Bakken trend in North Dakota has been one of the encouraging signs for us. The traditional Rockies markets as I mentioned before for us encompasses a pretty broad area and for the most part, some of those are up. Some of them are showing some weakness, but I would say overall, there's going to be additional rigs working in the Rockies. I think driven primarily by some of the resource plays, but at this point, I'm not sure I can quantify just how many.

Are you bidding any of your new rigs into that market?

None of the 15 ideal rigs are contemplated to move to the Rockies. They could, but we will have some new equipment coming into the Rockies by the end of the year. Some refurbed SCR rigs.

As far as your stacked rigs go, how many are 1500-horsepower or better?

Very limited number, Alan. To give you an exact number, I don't have it in front of me but I would say it would be less than five.

Okay. Excellent.

The key in the market for us is the 1,000 to 1500. It's sort of the under 750 and the 2,000 and over that we seem to have the -- the utilization issue.

Okay. Sounds good. And lastly, on the pumping side, just remind me, how strategic is Universal to you guys in the longer run.

I think that Universal is a very strategic company for us. As you know, it's one which has enjoyed substantial internally generated growth over a number of years, and, of course, now as one of the of the dominant players in the northeast, it is exceptionally well positioned for the developing Marcellus play. So we find ourselves with a business with a long-term excellent reputation in the northeast, just as the northeast becomes one of the most important plays. So it's extremely strategic.

Okay. So you wouldn't consider selling it then?

Well, I guess I would take the view that says that every asse is for sale, but I'm certainly not looking to sell it.

Okay. I will turn it back. Thank you.

And your next question comes from Kurt Hallead. You may proceed.

It's Kurt Hallead. I have a new name every quarter. Yes. So just in the context of you have a commentary, you referenced a quote about price increasing at a modest race versus the land rate. Your sequential quarter progression doesn't depict that. Just are you thinking it's going to be more of a momentum builder in the second half than in the second quarter then? Is that how I should interpret that?

Yes, Kurt, this is John. U.S. -- our guess for U.S. average revenue per day for the second quarter matches that of first quarter at 18,600. What's happening to get a $300 decline is that Canadian activity drops to near zero in the second quarter, and the Canadian average revenue per day is above that of the average for the company in the first quarter. So I think what we've suggested to you is that on a U.S. basis, our revenue per day bottomed in the first quarter and will remain at that same level through the second. With the increases in rates that were mentioned, by third quarter, you would expect that continues but we would see an increase in average revenue per day of some amount.

Okay. And then on NOV's call yesterday, they mentioned that there was an increase in inquiries for new land rigs after obviously they struck a decline in 2007. Can the market really afford to take on additional capacity at this point before we get through the -- through the absorption phase?

I guess I can't say that I have heard the NOV conference call yesterday. It was our day for our board meeting, so I can't speak to what was said, but I can say that we're not expecting to see a huge number of new rigs built this year. We do expect to see the new rigs that were commissioned in prior years being brought to the market this year, and frankly, we wouldn't expect it if new rigs were ordered currently that they would be in the marketplace in the next immediate quarters.

Okay. And then your comment about your positioning in the Marcellus Shale, clearly it's a long standing position in Appalachia and maybe something that investors aren't aware about. My question is, with the ramp up in activity expected there, there appears to be no shortage of frac companies wanting to get a toe hold in that market. Does that concern you at all with respect to your ability to maintain your position? Does it concern you in any way that it's going to hamper your ability to get pricing power?

Kurt, this is Doug. We have seen a number of competitors move into that marketplace. Obviously, we have some concerns like we would in any market, but, again, we think we're well positioned with people and equipment and with our reputation in that market place. We're pretty comfortable with where we see the business volumes going, that we will get more than our fair share of the work that comes up in that market place.

That's the share. What about the pricing.

I think any time you have competitors come into a new market, sometimes some of them do some silly things to gain market share. We can only respond and react to those things. But I do believe that if that place takes off like we think it will, there will be more than enough work for the people that are there.

Kurt, I also think that by virtue of the reputation which we long enjoined in that market place as being the premium service provider, that price alone won't be the driving factor.

Thank you.

And your next question comes from Marshall Adkins. You may proceed.

Good morning, guys. On your guidance, you suggest costs would be pretty stable next quarter. As you bring some of these rigs back -- more rigs back online in Q3, Q4, are those going to increase your costs at all or do you think that you can kind of hold them stable where we are here?

Marshall, I will take the first shot and let John and Doug join the parade. Initially, as you know, as you spread your fixed costs over a greater number of rigs running, you find some ability to actually find your costs decreasing. So in part, giving you a flat number, in my mind, reflects both the cost of putting those rigs to work, and the slight offset of more rigs running and being able to spread costs over that larger array. That's the sort of most immediate term expectation. Longer term, going out and further, as you know, we don't try to give guidance beyond the first -- the next quarter, because we have very limited visibility, but obviously to the extent to which you'd e see a major change in the business, you might see some changes in costs as well longer term.

Okay. Let's talk about capital, your cash allocation. You bumped up the dividend a little bit. I've got your CapEx, , for this year, coming in close to $500 million. When you divide it out between stock buybacks dividends, and obviously the CapEx program you've had ongoing, where do you see that kind of panning out over the next year or

Marshall, our expectation for this year, was with the CapEx, as you put it accurately, approximately $500 million expected CapEx spending for the year, plus the dividend, we thought that we would probably be about cash neutral for the year with potentially a very small amount of buyback. So that's kind of what our picture is. The picture remains that way with the increase in the dividend, and I -- I believe that -- we think right this minute that we are about break even for cash for the year.

Okay. Helpful. And on the CapEx, and this will be the last one I will bug you with. Help me understand where most of that is going to be going. Is it going to be upgrades or, , the new builds or more drill pipe or, , just kind of generally speaking, where -- where does

Well, Marshall, of the total $500 million, almost 80% of that goes to the drilling company. It's kind of a rough number, but certainly the 14 new rigs that we will get to the market place this year, we paid for most of those components a year ago, but rigging them up, there's obviously some additional costs to get them to the field. That's a good-sized number here this year. Almost $50 million. We have about $185 million on rig upgrade, capital expenditures this year, which is 1600-horsepower pumps, it's new mud systems, all the things you would expect that are what I would call major equipment upgrades. We do have in this year's plan five refurbed rigs to like-new condition. That, again, is a significant amount of money.

You mentioned tubulars. We are in very good shape with tubulars, our tubular capital expenditures this year are significantly below where they had been in the last couple of years. We have some rig moving trucks and equipment. We always tried to keep our trucking fleet current and up to date. That's the basic components of it. I think we have given you some guidance before. The pressure pumping this year is almost $72 million. And our E&P business certainly has some capital expenditures as well.

Okay. And the like-new rigs that you just mentioned, how would those compare to the ideal rigs that you are just putting out right now?

Well, for the most part, we call them like-new but in essence, they are a new rig. In some cases, we have a refurbished draw works. In some cases we may reuse a mast, but for the most part, the rigs are virtually brand new.

So would they be very similar or do the ideal rigs have more top drives, automatic stuff, et cetera?

They are very well positioned. Most of these conversions we do are typically going as walking rigs, which are a very different style of rig. They are more suitable for these unconventional resource plays, but in terms of the componentry, these new rigs also have EDS systems. We are putting hydraulic cat walks. We put iron rough necks, so they are very, very similar to the new technology that you see on a brand new rig.

All right. Great, guys. Thank you all.

I want to add one thing to the answer that we gave, which I think is important and sort of bolsters an answer we gave to a question that Alan asked before. In respect of the ideal rigs, we believe that they are really second to none in the business, in terms of their performance and ability to drill. They are fast moving, as Doug pointed out. They are capable of drilling. They are capable of all of the particular plays that are now -- so -- becoming such an important part of the drilling industry. Also at the same time, our walking rigs are another asset that we think we have developed that we believe are second to none for other kinds of applications. And so what I really want to emphasize is that Patterson-UTI has two different sets of rigs that are second to none, but for different kinds of applications and that we're able to offer these to our customers for different kinds of drilling purposes.

Fantastic. Can I give you a discount for that advertisement? Thanks.

Your next question comes from Arun Jayaram. You may proceed.

Arun, we will give you your name back.

Real quickly, going back to the CapEx question, if you look at the quarterly CapEx, in contract drilling of $67 million, that was the lowest level we saw since the second quarter of '05, yet you still believe the contract drilling will be a little bit over $400 million. Is that just timing related or is there the potential for CapEx to come in below that?

Well, Arun, it really is a timing issue. We had a lot of componentry and things coming in during the fourth quarter and sometime last year. We've re-looked at our capital budgets and fully still believe that we will spend the amount we got for the year. I think you will see an acceleration of those expenditures in the next three quarters.

Fair enough. Second question is, I was wondering, you are seeing a nice uptick in terms of your U.S. rig count. Are the increases you are seeing in your traditional backyard areas, are there new emergent areas for you guys in terms of new markets?

Well, I think it's a little bit of -- a lot of the markets have seen some uptick. We have seen some encouraging signs in south Texas. We actually put a few more rigs to work in our backyard in West Texas. But to say that we are not seeing a lot of interest in the new shale plays, I think would be an understatement. Certainly we plan on having -- currently we have three rigs working up in the Appalachians. By the end of the year, we plan -- we have commitments today to take another three rigs up there. We are putting rigs into the Fayetteville. We have seen just a general increase in gusts' budgets and I think it's pretty -- customers' budgets and I think it's pretty universal, potentially, with the exception of Canada.

I got you. Last question. I note this hasn't historically been a big area for you but just looking at Louisiana, on the Baker count, the rig count in Louisiana is down 22% or so year-over-year. Any comments on why it is been so weak in Louisiana?

It traditionally, Arun has not been a real strong market for us. It tends to be slightly deeper drilling. We have not had a lot of rigs over there, over time. I can only surmise that some of the deep wells just aren't being drilled over there anymore and there's better opportunities elsewhere.

Fair enough. Thanks a lot, Doug.

And your next question comes from Waqar Syed. You may proceed.

The DD&A was lower than the fourth quarter. I would expect it to go up with some of the new rigs coming in. Can you explain why that is and what's your guidance for the year for total company-wide DD & A.

I think the decrease in quarters. One is less impairment, very low impairment in the E & P business and also on the drilling side, we had some assets that became fully depreciated. Many of the assets in our business are five or ten year lives and if you think back five and ten years, those dates occurred back around '97, '98 and 2001, and 2002, so many of the periods of large capital expenditures, some of those items are becoming fully depreciated. Looking at the second quarter, I would think depreciation somewhere towards $68 million would make some sense with depreciation for the year being somewhere around $280 million.

Great. And then on the Marcellus share, Doug, you have done any preliminary work to see what will be the right rig in that market once you have significant development drilling pickup in that market?

Well, we -- we obviously believe that the right rigs are going to be Patterson-UTI rigs.

Good. The rig design, is it like light rigs? What kinds of rigs would be needed there?

Well, that's a very good question. I think it is very preliminary, early in the development of that field to make some conclusions at this point. As you know, we moved three pretty big rigs in excess of 1,000-horsepower rigs up there almost a year ago. And us working with our customer in that environment, we have already determined that we'd fine tune what is really required up there. I think it will be -- to be honest with you, I think it will take some period of time before we exactly figure out the type of equipment that you are going to need. The operators that we worked for up there certainly have different drilling programs, different casing designs, and that certainly has some impact on the style of rig, but we do certainly have an idea in mind. We've watched the development of the Barnett Shale very closely, and I think we have learned as an -- as an industry, we learned a lot of things. I do believe that in some period of time, you will see some pad-type drilling in that environment and, again, we think we are very well positioned if that, in fact, happens.

Okay. And then if you look at the whole Pennsylvania, West Virginia area region, there are a number of new E & P entrants. These are people that have not traditionally been there, maybe only the last year or so, the big guys. And so your historical reputation on the pressure pumping side and relationships, are they going to be as relevant going forward, considering that you got -- the big players are going to be relatively the newer guys that go into that market?

Well, I think they will. Certainly in a lot of the players that are moving up there are people that we worked for here in the rest of the U.S. We've done a pretty good job, I think, of telling people. We helped a lot of customers that have gone up there, because we have the infrastructure and the people on the ground. So I think certainly having that local reputation and having the experience in that market is going to play very well for us.

Now, if, some of your competitors have not been there traditionally. If they take their existing, let's say, equipment out of -- out of Texas, the big spreads and all, would they work in that environment or do they need to redesign equipment to suit to that market and the weight requirements and all that on the bridges and roads there.

Well, I certainly can't generalize. I'm not exactly sure what everybody else's equipment might look like, but you are dead on right that there are some requirements up there in terms of weights on roads and bridges and things and driving up creek beds and river beds as opposed to driving on gravel roads that will have some impact on people who are trying to move equipment into that market.

Okay. And then just last question on the labor cost of wage increase, my understanding is that the ages have not really gone up the last two years. Do you see those going up now and are they going to be the straight pass through to the customer or do you think that margins could come under pressure because of that?

Well, Waqar, we have not seen waste pressure for our drilling activities to date, as you mentioned. The last real change was about two years ago, two years ago second quarter. In terms of the looking forward, the contracts are set whereby wage increases are a pass through, so my expectation is that that's what would occur.

Thank you very much.

(OPERATOR INSTRUCTIONS). Your next question comes from Kevin Pollard. You may proceed.

Thanks. Good morning. I just had a couple of real quick questions. First of all on the ideal rig, that seems to be working out, fairly well for you. I was wondering what your thoughts might be on, you know, when you would consider, perhaps ordering another batch of say, 15 of them and having them ready to rig up, especially since the lead times are likely to extend out. And if you could talk just a little bit also on how you weigh that decision on whether to go with additional new builds or t put more money into your refurbishment program.

Kevin, thanks. The answer to that question is that we take as a management the job of allocating capital really seriously. We're quite proud of our record over the past however many years. You can look at the five year record of over 20%, 24% kind of returns on equity, unleveraged and see that we have always kind of given that a huge focus, the concern about what our returns are and how to, in effect maximize them. We are always, in terms of looking at our CapEx budget, giving consideration to what's in our fleet, what's in our fleet that can be upgraded to a certain level, and what additional do we want to have in terms of capacity. So we're kind of looking at it from several different perspectives. We expect to put the last of the ideal rigs into operation, into the field at the end of this year, '08, or the beginning of next year, and, yes, we are giving consideration to whether we want to order additional rigs and what those rigs might be and who might be the manufacturer.

We are always considering other manufacturers. We are also considering other kinds of rigs. We think these questions require a fair measure of subtlety, and one of the things I would like to emphasize is that in respect to the ideal rigs that we bought, we bought components from National Oil Well, and we assembled them, including, other components that were bought from other manufacturers into a rig that we believe is unique to Patterson-UTI. And so I would like to make it clear that when we do this, it's a sort of multi variable analysis, trying to match the perfect rigs for the future and trying to really anticipate what our customer needs will be. Doug, I don't know if you want to add anything to that.

No, I can't add much to that, Mark.

Being fair to characterize, as we think out over the next 12 months, it's most likely going to be some sort of combination of additional new builds beyond the 15 as well as further refurbishment activity?

Let me say this to you, Kevin, the plan for '08 that we developed at the end of '07 and the beginning of '08 was for us to put into the field these -- the remainder of the 15 rigs that we spoke about, to do in addition, I believe it's five upgrade rigs, including in that group some walking rigs. So there's a combination of assets that was our plan for the development. As the year unfolds, we reconsider that, literally, probably at least monthly, if not more regularly than that, to make sure the direction we are going in is correct. You are asking this question, like do we have a different opinion today? Well, the answer is our opinions are always kind of undergoing some refinement, but I'm not ready to say to you today that we're changing from that plan that was sort of set forth at the beginning of year.

Okay. Fair enough. And then if I could just switch over to the pressure pumping business real quick. I understand, John, when you said that you were putting $72 million of capital in that business this year.

That's correct.

What kind of capacity increase for that business? Do we think about the number of jobs or whatever metric we want to look at that that would get us to think about the longer term growth of that business? Would that bump 15% or some sort of --

Well, let me just give you a brief idea. We should exit '08, and I will talk in terms of horsepower capacity up there. We are probably adding 30 to 35%, upping our own capacity in fracing capability. We are probably increasing our nitrogen capacity up there by about 20% and we are increasing our cementing capacity up there again about 20%. So this is just compared to our own capacity at the start of the year.

Right. Okay. That's helpful. Would the emphasis be on growth more on the fracing side where we expect to see the revenue for the job trend out even in a flattish price environment as you are doing more revenue intensive jobs.

The traditional frac job in the northeast has typically required 1500 or 2500-horsepower to get a vertical frac done. The vapor horizontal fracs are probably going to require 20,000 or upwards horsepower. So certainly the revenue per job. The horizontal fracs could be in excess of $1 million to give you some idea. It's a huge step change from just the traditional fracs that we have done in the past.

Okay. Thanks. That's real helpful, Doug.

And your next question comes from Geoff Kieburtz.

Good morning, Geoff.

This is a technical question and maybe it's too complex and too rife with terminology problems to answer but in Neighbors' conference calls, they made a more definitive statement about the -- the benefits of purpose-built rigs than I heard them make before. It seemed to be in contrast to some of the comments I heard from you guys. In terms of the differential drilling efficiency, I think Gene even went to far as to say that, the efficiency is so great in some applications that you couldn't give a conventional rig away, would seem awfully extreme. Can you shed a little bit of light on this? How should we think about the serviceability of different kinds of rigs, and do we need to think about it for conventional-type reservoirs separately from unconventional reservoirs or can you give us any kind of greater insight on that?

Geoff, let me try to respond to that first and then I will let the other guys weigh in if they wish to but I'm not going to comments on the comments that he made.

No, I understand. It was just -- I think a lot of people heard it. It was more extreme than I heard before, and certainly something --

I think it's probably a little extreme. The big difference that we've seen in the drilling industry comes down to two or three things. It's bigger pumps which get you more fluid volume and pressure at the bit. It's things like top drives which can certainly help in terms of drilling horizontal wells. And quite frankly, a lot of things probably move in rig up times. So there's no question that the new rigs we have designed and I presume that other people have done, incorporate all of those three things on their rigs. Having said that, you can also take existing rigs and virtually do the same things so that you can -- add those bigger pumps to a legacy rig. You can add the top drives. Certainly it requires some modifications, but you can accomplish a lot of those things to the existing fleet, and get most of the benefits that you are going to see out of the brand new technology.

Okay. When you say most, I mean, is there -- can you identify what aspects of a rig are simply not worth trying to modify that if you are going to change X, it just makes more sense to build from scratch?

Well, it may be hard to answer that but I would say basically -- I will give you an example. If you require a 500-ton top drive, you are probably not going to be able to put that on a legacy rig without some major modifications to the mast and potentially the substructure. And once you start talking about replacing the mast and the substructure, you might as well think about a new rig.

Okay. So it's really -- it's really, lifting capacity, that you just can't modify up to?

I would say, generally, that's correct.

Okay. Great. Thank you.

And you have no questions at this time.

Okay. Well, then we'll thank all of the participants for their being with us today on the conference call and look forward to speaking with you at the end of next quarter. Thanks, everybody.

Thank you for participating in today's conference. This concludes your presentation. You may now disconnect. Good day.