Good day ladies and gentleman, and welcome to the first quarter 2008 Patterson-UTI Energy, Inc. earnings conference call. (Operator Instructions) On the behalf of Patterson-UTI Energy I introduce Mr. Jeff 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 which state the company’s or management's intentions, beliefs, expectations, or predictions for the future, are forward-looking statements. It is 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, regulization, 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 in 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 statement 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 pubically update or revise any forward-looking statements. And now it is my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thank you, Jeff. 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 would now like to review the results 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 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 totalled $77.4 million, or $.50 per share, compared to $116 million or $.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 $.16 per share from $.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 12, 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 $9.00 and prices have remained comfortably above $9.00 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 place. 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 31, 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 an 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 south Texas 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…

Thank you Doug. I would now like to discuss and to make a few observations of 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 the 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) Your first question comes from Mike Urban. You may proceed sir.

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

Well Mike, let me, let me start and throw it to Doug second. There is, as you correctly point out, the idle capacity is held by Patterson and by neighbors that we believe, or 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 is relatively limited in capacity and we think that our customers are starting to see, as they want to increase their drilling programs, a shortage of the kind of equipment that they want to use and we believe we are fortunate to have that equipment and to be able to meet that demand. But there is not so much of it available that we think that, that that the relative shortage of what is 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 started to see some signs of some price increases in certain markets and with certain kinds of equipment. I think that 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 are having those conversations but we are being very careful in the marketplace today.

Okay great and–

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

Okay, and you also had mentioned 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 areas have been a little bit more challenging markets, but the traditional Rockies markets we think are going to strengthen throughout the rest of the year.

Okay great, thank you.

The next question comes from Alan Laws. You may proceed

Good morning. I have got a couple here on first on the 15 rig packages you have there from NOV. You have one active, I think you said that last quarter you were going to have two more, you assembled two more and I did not quite understand what you said there with your plans for the rest of the year for the other packages.

Okay Alan, let me try and clarify that. We, during the quarter, we completed an additional two so at the end of the quarter we had three out in the field working. Within two weeks, or 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 eight. And there is an additional seven rigs that we expect to have completed by year end.

Okay. All right. Are these going out on just into the spot market or are you getting term contracts for these or?

We have primarily been putting them into the spot market.

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

Well, I guess I will say I am not going to 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 is 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. Could you talk a little bit about what your expectations for the pace of that recovery, we are at record recounts now and we have not seen the Rockies move and our expectations were that they it was going to surge a lot after the snow is gone. Where are you guys on your expectations for how many rigs you think you will have active by say the end of the third quarter.

In the Rockies?

Yes.

Well, I am not sure I can share that number with you. We just do see some, we saw some sloppiness in Q1 that we think will correct itself. I do not 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. But 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 are showing some weakness. But I would say overall there is going to be additional rigs working in the Rockies. I think driven primarily by some of the resource plays. But at this point I am not sure I could 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 into the Rockies by the end of the year. Some refurbed SER rigs.

Okay. As far as your stacked rigs go, how many of them are 1,500 horsepower or better?

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

Okay, excellent.

The sweet spot in the market really for us has been the 1,000 to 1,500. It is sort of the under 750 and the 2,000 and over that we seem to have 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 is one which has enjoyed substantial internally generated growth over a number of years and of course now, as one 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 importance plays. So it is extremely strategic.

Okay. So you would not consider selling it then?

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

Okay. I will turn it back. Thank you.

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

It is Kurt Hallead.

Hi Kurt, how are you?

I get a new name every quarter.

It is true.

Yes, so just in the context of the commentary, you referenced that about price increasing at a modest rate for the land rigs. Your sequential quarter progression does not depict that. Are you thinking it is going to be more of a momentum builder in the second half than the second quarter then, is that actually how I interpret that?

Yes, Kurt, this is John. Our guess for U.S. average revenue per day at second quarter matches that of first quarter at 18,600. What is 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 at the average for the company in the first quarter. So I think what we have 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, you know by third quarter you would expect if that continues that we would see an increase in average revenue per day of some amount.

Okay. Then on NOVs calls yesterday they mentioned that they are getting significant increase in inquiries from new land rigs after obviously a sharp decline in 2007. You know, can the market really afford to take on additional capacity at this point before we get through the absorption phase?

You know, I guess I cannot say that I heard the NOV conference call yesterday. It was our day for our board meeting so I cannot speak to what was said. But I can say that we are 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 would not expect 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 has been a longstanding position in Appalachia and probably something that maybe the investors are not aware about as your U.S. plans only position. And my question is with the ramp in activity expected there, there appears to be no shortage of you know, frac companies wanting to get a toehold in that market. Does that concern you at all with respect to your ability to maintain your position, and does it concern you in any that it will 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 are well positioned with people and equipment and with our reputation in that marketplace. We are pretty comfortable with where we see the business volume is going, but we are going to get more than our fair share of the work that comes up in that marketplace.

That is the share. What about the pricing?

Well I think that anytime you have competitors come into a new market, some times 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 play 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 have long enjoyed in that marketplace as being the premium service provider that price alone will not be the driving factor.

Thank you.

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

Good morning guys. On your guidance you suggest cost would be pretty stable next quarter. As you, as you bring some of these rigs back, more rigs back online in Q3 and Q4, are those going to increase your costs at all or do you think that you can kind of hold them stable while 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 is the sort of most immediate term expectation. Longer term going out further, as you know we do not try to give guidance beyond the first, the next quarter because we have very limited visibility. But obviously to the extent to which you would 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 have bumped up the dividend a little bit. I have got your CapEx you know for this year, you know coming in you know close to $500 million. When you divide it out between stock buybacks, dividends, and obviously the CapEx program you have had ongoing, where do you see that kind of panning out over the next year or so?

Marshall, our expectation for this year was that with CapEx at, as you put it accurately, of approximately $500 million expected CapEx spending for the year plus the dividend we though we would probably be about cash neutral for the year with potentially a very small amount of buyback. So that is kind of what, what our picture is. The picture remains that way with the increase in the dividend and I believe, we think right this minute is 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 bug you with, you know help me understand where most of that is going to be going. Is it going to be upgrades, or you know the new builds, or more drill pipe, or you know just kind of generally speaking where is that going?

Well Marshall, of the total $500 million almost 80% of that goes to the drilling company. It is kind of a rough number but certainly the 14 new rigs that we will get to the marketplace this year we paid for most of those components a year ago but rigging them up there is some obviously additional costs to get them to the field. That is good size number here this year. Almost $50 million. We have about $185 million on rig upgrade capital expenditures this year which is 1600 horsepower pumps, its new mud systems, it is all the things that you would expect that are what I would call major equipment upgrades. We do have in this years 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. A lot of tubular capital expenditures this year significantly below where they have been the last couple of years. We do have some additional capital in for rig moving trucks and equipment. We have always tried to keep our trucking fleet current and up-to-date. So that, that is 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 that you just mentioned. How would those compare to the IDEAL rigs that 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 you know 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 rigs also have EDS systems, we are putting hydraulic catwalks, we put iron roughnecks, so for the most part they are very, very similar to the new technology that you would see on a brand new rig.

Right. Great guys, thank you.

Marshall, I want to just add one thing to the answer we just 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 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 are able to offer these to our customers for different kinds of drilling purposes.

Fantastic. Is Pete going to give you a discount for that advertisement Thanks guys.

And the next question comes from Arun Jayaram. You may proceed.

Good morning guys

Hello Arun, we will give you your name back.

Really quickly, going back to that CapEx question. If you look at the quarterly CapEx in contract drilling is $67 million that was kind of the lowest level we have seen since the second quarter of ’05. Yet you kind of still believe the contract billing CapEx 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 that full year guidance level?

Arun, I think, Arun it really is a timing issue. We had a lot of componentry and things come in during fourth quarter and some time last year. We have re-looked at our capital budget and fully still believe that we are going to spend the amount that we got for the year. I think you will just see an acceleration of those expenditures in the next three quarters.

Fair enough. Second question, 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 or are there new emergent areas for you guys in terms of new markets?

Well I think it is a little bit of, a lot of the markets have seen some uptick. We have seen some encouraging signs in south Texas. We have 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 these new shale plays I think would be an understatement. Certainly we plan on having you know currently we have three rigs working up in the Appalachians. By the end of the year we plan and 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 customers budgets and I think it is pretty universal, potentially with the exception of Canada.

I got you. Last question, I know this isn’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 has been so weak in Louisiana?

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

All right, fair enough. Thanks a lot Doug.

And the next question come from Waqar Syed.

John, the DDNA for the quarter on the drilling side was lower than the fourth quarter. I would expect it to go up with some of the new builds coming in. Could you explain why that is and what is your guidance for the year for total company wide DDNA?

Yes, I think the decrease between cores has a couple of components to it. One is less impairment, we have had very little 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, you know, five or ten year lives and if you think back five and ten years those dates occurred back around ’97 and ’98, and 2001 and 2002. So many of the periods of large capital expenditures some of those items have become fully depreciated. Looking into the second quarter I would think depreciation somewhere toward $68 million would make some sense with depreciation for the year being somewhere around $280 million.

Great. And then on the Marcellus Shale, Doug have you done any preliminary work to see what would be the right rig for that market once you know you have significant development or link pickup in that market.

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

Okay. In terms of rig design, you know, is it bed drilling[ph 40:21], is it like light rigs? What kind of rig would be needed there?

Well it is very good question. I think it is very preliminary or 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 we have fine tuned 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 you are going to need. The operators that we have worked for up there certainly have different drilling programs. Different casing designs. And that that certainly has some impact on the style of rig. But we do certainly do have an idea in mind, you know we have watched the development of the Barnett Shale very closely and I think we have learned as an industry we have 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 who have not traditionally been there, they have only been there for maybe the last year or so, the big guys. And so your historical reputation of the pressure pumping side and relationships, are they going to be as relevant going forward? Considering you have got you know 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 have worked for here in the rest of the U.S. We have done a pretty good job I think of telling people, we have 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 you know some of your competitors have not been there traditionally, if they take their existing let’s say equipment out of out of Texas, you know spreads and all, would they work in that environment or they need to redesign equipment to suite to that market and you know weight requirements and all of that on the bridges and roads there?

Well, I certainly cannot generalize. I think everybody’s equipment, I am not sure exactly 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 that are trying to move equipment in to that market.

Okay. Great. And then this last question on the labor cost wage increases, my understanding is that wages have not really gone up for the last two years. Do you see those going up now and are they going to be this rate passed through to the customer or do you think that you know margins could come under pressure because of that?

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

Okay. Great. Thank you very much.

(Operator instructions) And the 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 rigs, since you know 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 you know perhaps of ordering another batch of say 15 of them you know and having them ready to rig up, especially you know since the lead times are likely to extend out. And if you could talk just a little bit also you know in how you weigh that you know decision on whether to go you know with additional new builds or to you know 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 are 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 out 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 is in our fleet, what is 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 are kind of looking at it from several different perspectives. That said, we expect to put the last of the IDEAL rigs into the, into operations 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 manufactures into a rig that we believe is unique to Patterson-UTI. And so I would like to make is clear that that when we do this it is sort of a multi-variable analysis trying to match the perfect rigs for the future and try to really anticipate what our customers needs will be. Doug, I do not know if you want to add anything to that?

No, I cannot add much to that Mark.

Do you think, being fair, does this characterize as we think out you know over you know say the next 12 months is most likely going to be a combination of additional new builds beyond the 15 you know as well as further refurbishment activity. It won’t skew…

Let me say this to you Kevin. The plan for ’08 that we developed at the end of ’07 in 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 is 5 upgrade rigs including in that group some walking rigs. So there is a combination of assets that was our plan for the development. You know as the year unfolds we reconsider that literally probably at least monthly if not more regularly than that, to try and make sure that the direction we are going in is correct. So, I mean you’re asking this question as if like do we have a different opinion today, well the answer is our opinions are always kind of undergoing some you know refinement, but I am not ready to say to you today that we are changing from that plan that was sort of set forth at the beginning of the year.

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

That is correct

And what kind of cap, how, you know what kind of capacity increase for that business as we think about the number of jobs or you know whatever metric we want to look at you know that you could you know that would as we sort of think about the longer term growth of that business. Do you feel that would that bump capacity say 15% or you know 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 30-35% upping our own capacity and tracking capabilities. 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.

Oh, okay. That is very helpful. And you know, with the emphasis you know on growth more on the fracing side, do we expect to you know to see the revenue per job trend up you know even in a you know kind of a flat-ish price environment as you are doing more you know for revenue intensive jobs?

Yes, the answer I can give you there is that the traditional frac job in the northeast has typically required 1500 or 2500 horsepower to get a vertical frac done. The day per horizontal fracs are probably going to require 20,000 or upwards horsepower. So certainly the revenue per job these the horizontal fracs you know could be in excess of $1 million. Gives you some idea. So it is just a huge step change from just the traditional fracs that we have done in the past.

Okay guys thanks. That is real helpful.

And the next question comes from Geoff Kieburtz. You may proceed. Geoff Kieburtz –Citigroup: Morning. This is I guess a technical question really and maybe it is too complex and too ripe with terminology problems to answer, but in Neighbor's conference call they made a more definitive statement about the benefits of purpose-built rigs and I had heard them make before it seemed to be in contrast to you know some of the comments I have heard from you guys. You know, in terms of the differential drilling efficiency I think Gene even went so far as to say that you know the efficiency difference is so great that you know in some applications you could not give a conventional rig away, which seemed awfully extreme. Can you shed a little bit of light on this? What 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 and respond to that first and then I will let the other guys weigh in if they wish to. But I am not going to comment on that comment that Gene made. Geoff Kieburtz –Citigroup: No, I understand. I was just sort of, it was just I think a lot of people heard it. It was more extreme than I heard before. Certainly something to be.

Yes. I think it is probably a little extreme. The big difference, I think, that we have seen in the drilling industry they probably come down to two or three things. It is bigger pumps which get you more fluid volume and pressure at the bit. It is things like top drives which can certainly help in terms of drilling horizontal wells. And quite frankly, the last thing is probably move and rig up times. So there is no question that that the new rigs we have designed and I presume that other people have done, incorporate all those three things on the rigs. Having said that, you can also take existing rigs and virtually doing the same things so you can add those bigger pumps to a legacy rig. You can add top drives. Now certainly it requires some modifications, but you can accomplish a lot of those things to the existing fleet and get more of the benefits that you are going to see out of the brand new technology. Geoff Kieburtz –Citigroup: Okay. When you say most. I mean is there can you identify what aspects of the rigs are simply not you know trying to modify that if you are going to change x it just makes more sense to build from scratch?

Well you know it may be hard to answer that but I would say basically, to 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 a mast and a substructure you might as well think about a new rig. Geoff Kieburtz –Citigroup: Okay. So it really it is really you know lifting capacity that that you just cannot modify up to

I would say generally that is correct. Geoff Kieburtz –Citigroup: Okay. Great. Thank you

We have no questions at this time.

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

Thank you for attending today’s conference. This concludes your presentation. You may now disconnect. Good day.