Good day, ladies and gentlemen and welcome to the Q4, 2007 Patterson-UTI Energy Inc. Earnings Call. My name is Mike, I will be your operator today. At this time, all participants are in a listen-only mode and we will be facilitating a question-and-answer session at the end of today's presentation. (Operator Instructions) As a reminder, ladies and gentlemen, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call Geoff Lloyd on behalf of Patterson-UTI. Sir, please proceed.

Thank you very much. Good morning and on behalf of Patterson-UTI Energy, I would like to welcome everybody to today's conference call to discuss the results of the three and 12 months ended December 31, 2007. 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 and 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 affect on day rates, rig utilization and planned capital expenditures. Excess availability of land 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 availability 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. The company undertakes no obligation to publicly update or revise any forward-looking statements. Now I would like to turn the call over to Mark Siegel for some opening remarks to be followed by questions and answers. Mark?

Thanks, Geoff. Good morning and thank you for joining us today. I hope that,[Author ID1: at Thu Feb 14 19:24:00 2008 ] 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 briefly the results for three and 12 months ended December 31, 2007. I will then turn the call over to Doug Wall, Patterson-UTI's President and CEO, 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 $85.1 million or $0.55 per share compared to $156 million or $0.97 per share for the three months ended December 31, 2006. Revenues for the just completed quarter were $521 million compared to $638 million for the fourth quarter of 2006. Net income for the twelve months ended December 31, 2007, totaled $439 million or $2.79 per share compared to net income of $673 million or $4.02 per share for the twelve months of 2006. Revenues were $2.1 billion for the twelve month period ended December 31, 2007, compared to $2.5 billion for the twelve months of 2006. I would now like to turn the call over to Doug, who will discuss our operations for the quarter and provide some highlights and additional color.

Thank you, Mark, and good morning. I would like to make a few brief comments on each of the operating divisions, and I will start out with the drilling company. For the quarter ended December 31, 2007, the company had an average of 241 drilling rigs operating, including 231 in the US and 10 rigs in Canada. This compares to an average of 243 drilling rigs operating, including 234 in the US and nine rigs in Canada for the third quarter. This represents the third straight quarter of relatively stable rig count with some minor changes in the mix between the US and Canada. During the fourth quarter a number of rigs were shutdown for the holiday season, negatively impacting our average rig count by about two rigs. Average revenues for operating day during the fourth quarter were $19,250 compared to $19,150 in the third quarter. Average direct costs for operating day were $11,110 for the fourth quarter compared to $10,840 for the third quarter of '07. An increase in the number of camps and boilers working in Canada during the quarter had the effect of increasing both average revenues and direct costs for operating day. Average revenues per operating day also benefited from a term contract buyout from an operator in the Rockies. Without these items, we believe our average revenue per operating day would have declined by approximately $200 compared to the third quarter. At the end of the year, we had 47 rigs working under long-term contracts of varying lengths. Of these term contracts, 12 are said to expire in the first quarter of this year. We do expect our customers to continue to utilize most of these rigs, but they will be at current market rate. We sum up, but for the most part, down. I'd…

Thanks, Doug. For the first quarter of 2008, we currently expect our rig count will be similar to the fourth quarter of 2007. In the first quarter, we expect a decrease of approximately $400 per operating day in margin, which includes the impact of market pricing of rigs coming off of long-term contracts. Recently, we have had some encouraging signs in the marketplace and we believe that the land rig market continues to stabilize. There were a very large number of rigs, primarily competitors coming off term contracts and it will be interesting to see the impact that they may have. We do think that for the near future the US rig count will remain in a rather narrow band. Of course, we expect that demand in Canada will fall dramatically sometime after mid-March as breakup beings. We expect the Canadian market, albeit a small market for us, will be soft for the remainder of the year. For the drilling industry in the United States in the lower 48, land rig counts have remained at relatively high levels throughout 2007. The combination of rig, new builds and reactivations of a last couple of years has caused in excess supply of rigs. We do believe however, that the construction of additional land rigs for the domestic market has slowed significantly. We believe that there is still some demand for fit for purpose new rigs to enter the market. Most importantly, we believe that long-term upward trend in the number of wells drilled will continue as it is the principal mechanism to meet demand for natural gas and to offset steep decline rates. To meet this expected increase in rig demand in the US, we currently have approximately 90 currently marketable land drilling rigs available to reactivate when the need arises. We…

Thank you, sir. (Operator Instructions) And our first question comes from the line of Kurt Hallead with RBC Capital Markets. Please proceed.

Hi, good morning.

Good morning, Kurt.

Just wanted, you said Mark, cash margin down $400 a day, first quarter versus fourth quarter. You said that you see some encouraging signs out there. Does that mean that you think that rates are going to stop declining or do you think the decrement will be generally less than what we've have seen in the fourth quarter and first quarter?

Kurt, let me break the question into two parts. The reason for the comment about the change in margin is the impact both in our company and other companies of term contracts expiring. That's the principle reason for that comment. Where in effect, you have an adjustment to market from a rate that may have been set 18 months ago, so that's the principle reason that we're giving that number. What we're saying is, that in the overall market we're seeing at current stabilizing of the market, that's the word we've used in our comments. So that's how they square those two thoughts, if that makes any sense.

Okay. Does that mean that you think that after this first quarter, it will come back to the question; do you think that pricing is going to stop going down or you think its going to go down on a less decrement?

It's going down at a much smaller decrement.

Okay. And then in terms of encouraging signs, you say there are a number of rigs coming off contract. Was that a reference to the industry in aggregate or was that reference specifically just to your stuff?

We have some coming off as I said in our remarks at the start, we think that the industry as a whole has a large number coming off.

Okay. And with the industry as a whole with a large number of contracts coming off, so your comments basically suggest that you don't see any of these rigs becoming increasingly more competitive with day rates relative to where the market is right now?

Well, the thought that we have is that there is sufficient demand for rigs at this point, such that we're not expecting undisciplined price competition as those rigs come off of term contracts. We think they'll go to a kind of a market rate and we think that market rate is showing fair degree of stability. I think I said in my remarks that we'll see exactly what happens. Obviously, it's impossible to predict in a very competitive rig market exactly how all the competitors will respond but we think there is reason for people to behave in a very disciplined form given a significant amount of demand for rigs at this time and starting of rig new builds.

That's fair enough. And my last one would be just, while you said you had 90 idle rigs. Do you guys, what's your estimate of the number of total idle rigs that are available in the market right now?

I think, Kurt, we have no particular special expertise on that. The number that's kicked around is 300. We wouldn't see any reason to change that. I think there is another large competitor of ours who has a similar number to the number that we just describe for ourselves and I think the rest is spread about the industry.

Right, and Mark, thanks.

Thanks, Kurt.

And our next question comes from the line of Geoff Kieburtz with Citigroup. Please proceed.

Thanks, good morning.

Hey, Geoff.

Could you quantify for us the magnitude of the term contract buy out?

It's about $100 a day, little less than that.

Okay. So that was the effect on margin and revenue?

Yes.

Okay, and kind of to continue on a little bit on this, the term subject. What was the average number of rigs that you had on term contract in the fourth quarter?

I don't have that.

Geoff, I would just be guessing it. We had approximately 12 rigs come off term contract during the fourth quarter, a similar number we just mentioned we will come off again in Q1. So the average number of term contracts is probably in the mid-50.

Okay.

We said at the end of the end year we had 47, 12 are set to expire to this quarter. We are thinking that the same number expired in the preceding quarter. So we don't have that number, but you can so back...

That's close enough. That's fine. Thank you. Are you signing any new term contracts? Or should we assume that term contracts expire but there is no new one being signed for the time being?

Geoff, I think for the most part, we are signing some what I would call some shorter term type contracts, but they typically are less than twelve months. In the past we've always considered a long-term contract something in excess of the year.

Right.

We've had a number of three months, six months, nine months extensions, but quite frankly we have not seen a whole lot of interest today in people signing up two and three year new contracts unless it's on new equipment.

Right, okay and what do you have coming into the -- at this point for first quarter or first half in terms of new equipment that is on term but not in the fleet yet?

Specifically that's on term?

Yeah.

The answer would be nothing.

Okay. That's great.

I mentioned we've got the two new rigs coming out. They are coming out virtually this week, but we did not plan term contracts with those two rigs.

Fine, I'm going to make a stab at this. I don't know if you have the numbers. You have an estimate of what your per rig day margin would be in the fourth quarter. If everything were on today's spot rate, if everything were mark-to-market, you had no term whatsoever?

Geoff, I don't have the calculation but my take is that it would not be significantly lower than where we are today.

Interesting.

Obviously, my take is it will be within $1000.

Okay.

But that's a stab in the dark on my part.

Yeah, I think that's fair we obviously haven't calculated that number but as you know we had certainly had less term contracts on some of our competitors.

Sure.

We have seen a number of them, a number of the early ones have come off, but as I mentioned, it's a hard thing to calculate, Geoff, because I would say we had some one year terms and two year terms and some three year terms.

Right.

I think John is probably pretty accurate in the answer he gave you.

Okay, great. And my last question is just simply on the fluid. You made, I think a non-committal comment about not seeing anything in '08 is going to materially change the fluids business. I am assuming that reflects a view on the Gulf of Mexico drilling activity. Is there anything particular that we should watch, is it the jackup count that would, if that goes up that we should expect something different from fluids than basically more of the same?

No, Geoff. I would say as you know the rig count in the Gulf of Mexico has declined year-over-year I think from 77 to about 55 or 56 today.

Yeah.

Our fluids business has been heavily reliant on four or five very specific customers in the Gulf

Okay

And those specific customers just are not as active as they had been in the last couple of years.

Okay, so it is not a broad market comment, it's really on those specific operators.

That's correct.

Great, thank you very much.

And our next question comes from the line of Arun Jayaram with Credit Suisse. Please proceed.

Good morning.

Hi, Arun.

I've got a couple of questions on capital. You mentioned you spent about $1.5 billion in the drilling business in the last four years. So wondering if you could give us a sense of how much of that was maintenance type of CapEx and how much of that was new builds and upgrades and alike?

Yeah, I don't have the full breakup of the number here, but the maintenance capital has over the last several years runs us in the area of $1,000 per drilling day. And I think that the maintenance capital component will be consistent over that period and that tubulars would be in addition to that.

Okay. John if you could estimate, you talked about 70 new and new-like rigs, how much did you spend on a per rig basis for those 70 rigs?

It would be less than $10 million starting to venture in guess and a guess would be somewhere in the $8 million per rig range.

Okay, that's helpful. In '08, you've talked about $480 million in CapEx for the drilling business. How many NOV new builds in --

That's $480 million in total.

In total, pardon me. How much for the drilling business and how many --

Let me give you some numbers for that Arun, it might be helpful. Of the 480, we are saying internally that we think approximately 70 goes into pressure pumping, approximately 30 into other businesses. So 480 becomes 380, the 380 that's then going into drilling gets allocated in the following way; approximately $130 million in maintenance, approximately $50 million to take those customized NOV IDEAL rigs and put them in the field along with some other, in effect re-furbs of rigs that makes them like new rigs. $190 million for upgrading our mud systems, top drives, pipe handling equipment and other systems which make our rigs more fit for purpose across the board and $10 million miscellaneous bringing you to a total of $380 million.

Okay. That's great detail, thanks. Doug, you've added I think 11 walking rigs and a handful of IDEAL rigs. Is that helping the mix and the margins on those substantially different than the 8135 you did this quarter?

Arun, I would say the answer to that question is, yes, obviously those rigs are going into the marketplace tighter day work rates, because they are in essence new equipment. We certainly have some short-term advantage in terms of repair and maintenance cost. But I think you also have to recognize they are much more sophisticated equipment to things with electronic drilling systems, hydraulic pipe handling equipment, iron roughnecks, SCR, also have, overall have higher ongoing upkeep cost. But generally, I think the margins on those rigs, we have been very pleased with them they have been helping the mix.

Can you quantify kind of where those margins are?

We would rather not do that, Arun.

Okay. Last question, guys, obviously you have been spending some money in Pressure Pumping. Could you give us a sense of what you believe the replacement cost of your Pressure Pumping businesses in Appalachia using current market prices for?

Arun, I don't think we think about the business the way you just described it. We have a business there that is more than just the sum of its equipment and its facilities. I mean, we have been a market leader in Appalachia for many years. The business has enormous know-how, it has enormous goodwill and we would never think about the business, in terms of its equipment replacement costs and for that matter by the way, we don't think that's an appropriate measure for measuring our drilling business or our fluids business. There is expertise in these businesses and goodwill and you can't just, in the old industry standard of saying, what it's worth in affect on a pure equipment basis. We don't think, makes much sense in the business with as much knowledge and sophistication as is currently is there.

Okay, fair enough, thanks a lot.

And the next question comes from the line of Marshall Adkins with Raymond James. Please proceed.

Well, Mark, I'm a little perplexed here. When I go, talk to investors, a lot of people perceive your fleet as a lower end fleet, but somehow you're keeping margins and rates as high or higher than a lot of your competitors. How's that happening?

Marshall, I think that the story that our rig fleet is inferior is one which our competitors would like the world to believe. I don't think it's a fair description of what we have. As you know the walking rigs that we have put in to market are among the most sophisticated equipment there is in the marketplace. In essence, I think you just kind of confirmed the answer to -- by your question, kind of the answer I gave immediately beforehand, which is that there is a lot of expertise in our drilling business and that expertise we think our customers appreciate. I'm amused that listening to a story one day in which one of our customers said that they were able to successfully do their E&P program, because of some very sophisticated technology that was brought to bear. The question was said to them what technology is that? Well Patterson-UTI was the answer and that's the technology. So I think that it's very easy to understate your competitor's abilities, which is what I think some people have done. I don't think it is true or correct.

Oh, it certainly appears to be showing up in the numbers. Pressure Pumping, pricing there has also done a lot better than elsewhere. Is that because of the geographic niche you guys have or is it the new equipment you've added or help me understand why your business there seems to be doing so much better than others?

Well, Marshall I think there is a variety of reasons for that. One, as you know, we are very solidly entrenched oil field service company up in the northeast. Our people have been there. We have an outstanding reputation in the marketplace. The business as you know up there has taken off. There are a lot of people very excited about the Marcellus Shale play and it's a very broad aerial extent. But I think we are known for our outstanding capabilities there. We have kind of feed the tiger quite a bit in the last couple of years to try and increase our capacity and very selectively we have made sure that we have pushed our pricing as well.

Okay, last question, Mark. You've done a better job than many in the oil service arena of getting cash back to the shareholders in a couple of different forms. What are your plans there going forward or are you still looking at ongoing share buybacks or are you going to start reinvesting in biz, obviously you have a pretty good CapEx budget this year. Help me understand what your plans are there?

Sure, thanks for the compliment first. We are quite proud of this combination we have been able to achieve. Significant reinvestment, $1.800 billion reinvested the business plus the $700 million that we've given back to the shareholders in our balance sheet that's still debt free as of today. So that we are really, that is something we're quite proud of. We just announced obviously that first quarter dividend is being paid out again at the end of March just as we have been doing for a number of years. In terms of the buyback plan, we have, as you probably know based on the numbers released this morning, $180 million left on our buyback authorization. We probably will not be spending a lot of money immediately given current market conditions and a desire to make a significant investment as is set forth in the CapEx plan. As we've been discussing already during this call and in our press release and our expectations for free cash flow generation from the business. On the other hand, to the extent to which there is excess free cash flow over and above what we invest in the business and we have historically used it to buyback shares. And I can't see any reason that we wouldn't follow that suit to the extent which there is excess cash flow over and above what we're going to reinvest in the business in CapEx.

But you probably wouldn't lever up at all the buyback stock. Is that fair?

Don't have current plans to do so, wouldn't rule it out as a never.

Okay, great. Thanks.

And the next question comes from the line of Ian Macpherson with Simmons & Company. Please proceed. Ian Macpherson with Simmons & Company: Hey, good morning.

Good morning. Ian Macpherson with Simmons & Company: Mark, I'm just curious about the remaining IDEAL over exit you're building out. I think you ordered that equipment from NOV about 18 months ago. Just curious what the strategy has been behind it, seems like you are taking your time in getting those rigs into your fleet and what strike me is beneficial to your mix, if those were working as opposed to being gradually phased in. So if you could maybe?

I will let Doug answer that. Ian Macpherson with Simmons & Company: Okay.

Ian, you are correct. We did order that equipment about 18 months ago. Most of it was delivered throughout 2007. As you know, we ordered 15 of them at one time. We decided last year in mid summer to put one of them together and introduce it to the marketplace. We had a very thoughtful process as to how we planned on introducing these to the market. As you know, at the time there were a lot of rigs, excess capacity in the market at the time. We decided not to, as a kind one fell swoop add a whole lot of additional capacity. We wanted to specifically look for incremental demand. We kind of stuck to our guns on that. I mentioned earlier we are planning on building two at a time. One in Victoria, one in Tyler and I am pleased to say that the two that we started in late November are moving to the field this week and should be spudding next week. We will start two more of them right away. Our plan is to continue to do that as long as we see incremental demand. And you are correct. We do see that all the margins and the rates on those rigs are higher. But we have very clearly tried to come up with a game plan not to flood the market with these rigs. Ian Macpherson with Simmons & Company: Okay. So I don't think I quite got that. What do you think the cadence is for two by two each quarter or each month, I didn't capture that part.

They take 60 to 75 days to put together. We might speed that up, we might slow it down depending on the demand, but we at least plan to have most of those rigs in the marketplace by the end of 2008. Ian Macpherson with Simmons & Company: Okay. If I get this, that's a quick follow-up on your, the 90 rigs that you have available on the sidelines, if demand does creep up to require some of those rigs, would you have a significant refurb cost associated with those or are they still warm enough that they could go into the market pretty seamlessly?

I think pretty seamlessly most of those rigs have worked, at some point in time within the last 12 months. We have analyzed rig-by-rig but as you know that 90 rig number it's not the same 90 rig depending on the area that we are working in. Most of the rigs today could go back to work very seamlessly. I would say there is some in the fleet that would require a minor amount of capital before we'd put them back to work. But for the most part they could go pretty seamlessly. Ian Macpherson with Simmons & Company: Alright, thank you.

And the next question comes from the line of Mike Drickamer with Morgan Keegan. Please proceed.

Good morning, guys.

Good morning.

Doug, we've seen a couple of transactions recently with a service company buying a land driller or land driller buying a service company. Given the experience you've on both sides of the fence here, I wanted your thoughts on this. You think this is a trend you'll see more of, is it a positive thing or are there going to be cultural issues in the integrations here?

Well, Mike I think looking at both of those deals, they are very specific deals. I think you've to look at them as transactions that the people knew each other on both sides. Obviously the one deal worth all [altamers] we're encouraged by that little bit. They've at least publicly announced that they may move some of those rigs internationally. We think that's good for the US markets. The second deal I think there is certainly some related parties on both sides of that deal. I don't see it as being a trend in the industry. I think for a long time the land drilling industry in general has been looked at as a separate entity and does not have a whole lot of, I guess what I would call synergies with some of the other oil field services businesses. Certainly in terms of bundling packages, I don't think it's a requirement. So I don't see it as being a trend that will continue. There may be certainly some international opportunities for people to do that. But I certainly don't see it as being a huge big trend.

Okay, then one of the other things people are looking at is moving rigs internationally as you have discussed here. Is this something you guys have looked at and would be interested in?

Well, we have looked at it. Quite frankly most of the deals that we have seen so are not terribly interesting to us. People assume that the international business by itself is just so much better. It's not necessarily the case. But as I said we are actively looking, but we have no plans in the immediate future to move rigs internationally. If the right deal comes along, we would certainly look at it, but for the most part there is a very limited number of opportunities. As you know the land rig market internationally is something like 850 rigs, which is smaller than the number of rigs that are just in Canada. So I think the opportunities are few and far between and you certainly have to pick your spots.

Okay, then. Mark or John, I am not sure which one of you want to take this. You commented about how the fourth quarter numbers were positively impacted by Canada. Would this mean that perhaps in the second quarter once we see the spring break up the impact on revenues and therefore also margins will be greater than what we've seen in previous years?

Yeah, I think we might have misstated or you might have misinterpreted that the comments about Canada had to do with higher revenue per day related to some incremental equipment that gets used in the first quarter. There is a similar offsetting cost from a margin perspective that's fairly neutral.

Okay.

But as you look to the second quarter, certainly the Canadian market is lower than the industry there, comes close to a shutdown in the second quarter while they work on equipment and get ready for the coming 12 months. So, my expectation or my guess is that we would see a sequential decline in drilling margin, somewhere towards maybe $300 to $350 in the second quarter that's a guess, which is incremental impact of he Canadian rigs not working yet most of the cost are in place.

Okay guys, that's it for me, thanks a lot.

And our next question comes from the line of Waqar Syed with Tristone Capital. Please proceed.

Hi. Could you provide some guidance on DD&A and G&A expectations for the next year?

Yeah, as we continue our capital program, depreciation will continue to ramp up. I mean if I look at kind of first, second quarter, I think first quarter would be somewhere around $66 million and then probably increasing $3 million, $2.5 million, somewhere between $2.5 million to $3 million per quarter depending on the timing of the CapEx when things come into the marketplace.

Sure.

G&A wise, I don't see it ramping up significantly but possibly somewhere around $0.5 million per quarter.

Okay. Do you expect any drop in the first quarter from the fourth quarter? If there is some seasonality to G&A in the fourth quarter or no?

You can have a little bit of that. Fourth quarter, you get a bit of a bump in some of the markets with some of the things that go on. But I wouldn't expect a significant adjustment for the first quarter.

Okay, good, one other thing. One of your competitors has been recently saying that they have introduced new rigs in not just the traditional unconventional plays but also in the conventional plays, and they think that even in the vertical well market, they have had some efficiency gains in that. I think in the West Texas area, third party reports are that they have recently drilled some of the fastest wells ever drilled in that market and they have just been operating there for about six months. Do you see any competition there from new rigs, even in the traditional vertical well market as well?

Well, I think the new rigs are going into all sorts of markets. I don't think it's just the unconventional plays. In fact, if you think so far two out of the three new rigs, the new NOV rigs that we've introduced to the marketplace are working in South Texas, which you would consider to be a pretty traditional vertical market. So I think you have to look at region-by-region. I don't think the new rigs are just specifically going in to the unconventional plays. There is a combination of new equipment going into all sorts of markets.

Now but even in like the shale vertical market in the West Texas area, which is something that you guys have dominated in, have historically had very good efficiency in that market?

We have not seen a lot of new rigs enter that market, obviously, there is one very specific case that I think you're referring to and we're still in that market competing against those new rigs. Interesting enough based on the data that we've seen from all of 2007, our cost for foot data is still 25% below that of those new rigs that are in that market. Well, all the stories about new fit for purpose equipment taken over and providing more efficiencies generally. I would say is true but there is some very specific markets that the facts just don't bear that out.

Yeah, thank you very much.

And the next question comes from the line of Pierre Conner with Capital One Southcoast. Please proceed.

Good Morning, gentlemen

Hey, Pierre.

First question is about, actually on Universal Well Services, can you just give us a feel for where you ended up on horsepower and then you indicated -- continue to add some more horsepower. What that horsepower number would be or what are you adding?

Yeah, Pierre, we've been adding a lot of horsepower throughout the various segments of that business, and we almost got to break it down by fracing, and Nitrogen, and cementing. I'll talk specifically about fracing, because it's probably the area that everybody is the most interested in. We exited 2007 just under $72,000 of horsepower. We think we'll exit '08 at something in the excess of $110,000. So, we have added a significant component of horsepower. To give you some idea, the average frac job in the Northeast, sort of prior to all the current interest in the Marcellus, was you can have a 1,000 horsepower to 2,000 horsepower to do one of the typical frac from the Appalachian. Some of these horizontal frac's are going to require somewhere between 15,000 and say 25,000 horse power on a location. So you just have to have enough equipment to make sure that you can do that and we plan on having enough equipment so that we can do at least two of those horizontal frac's at any one time plus handle all of our traditional business.

Right.

So I said that's on the fracing side, that's primarily what we have added. We have that at a lot of nitrogen stimulation capability as well, probably about 30% increase in our horsepower there. The cementing business we haven't really seen any huge big changes and quite honestly we've added some horsepower capability for cementing but its nowhere near the nitrogen and the fracing.

Okay, that's helpful. The next question is with the currently available fleet what would be the indication you would be looking for to begin to bring some of those rigs out and people asked a little bit about what would it take. So would it be incremental backlog on existing actual day rates improving just what's the context by which you would potentially bring those additional rigs out.

It's really a case-by-case decision in each market and with each rig made typically by the regional person in consultation with the operations people and marketing people here and in Houston and under ultimately Doug's decision making. But it's really case-by-case we'll look at demand in the marketplace, rigs available in the marketplace, pricing in the marketplace and all those factors and try to make a decision as per each rig. I want to try to emphasize it's not a top down, but rather a bottom up decision.

Okay, so it's where they would see the ability to put the rig to work without damaging current pricing or activity.

And also you're obviously not interested in mobilizing a rig, going through all the startup costs for one well commitment, you're looking for a multiple well opportunity and you're looking for a situation in which the pricing makes sense for that additional incremental rig.

Right, it seems like the pretty big asset there opportunity base and you mentioned the incremental demand still for fit for purpose equipment. Has it and this has obviously been brought up to spec currently, but is there an opportunity for real step function in it's operability, kind of example. Can you take equipment that you have and convert it into skateable rigs, has it been looked at and what's the magnitude of that kind of a thing?

Yeah, certainly we're looking at the fleet today and there is no question that you can take current equivalent and modify things to get a very, very efficient rig today. One of the things that we talk about all the bells and vessels that we put on the new technology rig, but in a lot of cases, single biggest impact has been higher horsepower triplex pumps and you can make a significant improvement in the efficiency of a rig just by putting bigger pumps on the rig. We do look at some other things; obviously you can reconfigure the backyards of rigs to get them to move quicker. When you get into EDS systems and top drive, it's a little bit more difficult just adding those things to older type rigs, some of the older mass and Derrick's aren't capable of handling top drives. But we've looked at all of those things and we have a very active program at improving the efficiencies of those rigs that we think it makes a lot of sense.

So you would potentially look at this fleet of marketable --

Oh, let me interrupt you. Not only are we looking at it, our capital expenditure plans for 2008 include significant capital to do just that.

Okay.

And part of the almost $200 million, that I described as part of the $380 million for CapEx for our drilling pump segment is going in to that exact issue of upgrading our pumps, our mud systems and the things that Doug was just describing which have the effect of, in fact taking a rig and making it virtually new in its application.

Okay. That's what I was looking for. So these compete with your fit for purpose.

Yeah. And let me say this to you. We have been doing this for a number of years.

Yeah.

I mean, one of things that I try to emphasize in the CapEx we've spent is we have been doing this and this is one of reasons why to go back to a prior question and a prior answer. We think that our fleet is of significantly different caliber than some of our competitors would like to acknowledge because of the capital investment program we have had for a number of years where we have in fact upgraded a large number of our rigs.

Alright. Okay.

That is the long answer.

Got it, thanks Mark and Doug. I will turn it back.

Thank you.

And the next question comes from the line of [Scott Gruber with Bernstein]. Please proceed.

Yes, good morning.

Good morning, Scott.

What's your contract roll off schedule in Q2 through Q4?

I don't think we have that information with us here.

Is it going to be about the same magnitude, 10 to 12 rigs rolling off per quarter?

Yeah. It's actually a little bit smaller than that.

I think, we think the first quarter was the most, was going to be the most dramatic and it would slow thereafter.

Okay. So your indication that the margin impact beyond the first quarter was mainly due to fewer rigs going off contract.

John, you want to respond to that?

And not a difference in the spreads to working rates?

I guess I would like to circle back to an earlier question. I'll play around a little bit with the math as Geoff Kieburtz asked his question and I think the impact of difference between --- if everything on term went to spot, how much that would that impact margin right now. I think that impact was less than $500 per day. Earlier we said it was $1,000 or less, I think it under $500.

So the rigs that are rolling off in the first quarter, they work at higher rates than the ones that are going to be rolling off the rest of the year?

I don't think you can say that. I couldn't answer that with any degree of certainty. Those rates, depends on when the contract was signed. We had contracts that were signed three years ago that have lower rates than contracts from, say a year ago. So it really is all over the math.

Okay. That's it.

Thank you.

And the next question comes from the line of Todd Garman with Peters & Company. Please proceed. Todd Garman - Peters & Company: Good morning. In Canada, Doug do you've any visibility as to activity levels in the back half of the year and has that changed recently one way or the other?

I really don't have that visibility and I couldn't culture the numbers on PSAC survey that everybody uses up there for activity, but I think, directionally, what we heard is that it was a pretty dismal survey. They expected very low levels of activity and we don't see anything on the horizon that gives us any great degree of comfort at the back half of the year and Canada is going to be very good at all. Todd Garman - Peters & Company: Do you see any signs now of clients taking rigs on windows where they can?

In Canada? Todd Garman - Peters & Company: Yes

Well, I think now, typically, in the winter time there is a lot of occasions that we drill are only accessible in the winter, so I think that kind of drilling today sort of is ongoing and it happened. I think the real question will be is what would the rig count look like coming out of breakup and I don't think it will be so much a question of customers looking for windows. I just think the amount of work up there after breakup is going to be few and far between. Todd Garman - Peters & Company: Okay, in the US and the Pressure Pumping business, is there anything on the product supply side that might prevent you from increasing or utilizing the equipment in which you intend to build here for the year, like whether it is gases or sand or..

Well, I would generally say, no. Sand is obviously an issue in the North East but we've found that we have got three or four different suppliers and because of our long standing relationship with those suppliers up there we have had access to some products and things that are going to be difficult for other people to get. But we think we have got our supply locked in. Todd Garman - Peters & Company: Yeah, but taker for your agreements for sand in that area?

Not that I am aware of. Todd Garman - Peters & Company: Okay, thank you.

And our next question comes from the line of Kevin Pollard with JP Morgan. Please proceed.

Thanks, good morning.

Hi, Kevin.

I just wanted to close a loop on these questions around your capital budget and the upgrading of the fleet, some of the stuffs that Pierre was just touching on. If I look at the substantial budget you've got for upgrading in the $50 million for the IDEAL rigs. How would your fleet of new or light new rigs stand at year end '08 versus the 70 that you have now?

You are saying what would the number be?

Right.

Well, it will be closer to 90.

And that includes all 14 additional IDEAL rigs.

Yeah, we put out the remainder of the ideal rigs plus the continued refurbs and some additional walking rigs that we are contemplating in '08. That number would get pretty close to 90.

Okay. Alright thanks. And if I could just switch gears over to Appalachian. You've talked a lot about your expansion program for the Pressure Pumping business, I know you've moved a few rigs into that market. I was wondering given the growth of that market's experience whether if you could talk about your plans on the rig side?

I think it's a pretty competitive opportunity and I think we'd just like to tell you that we think it's a really interesting opportunity.

Okay, thanks a lot.

Gentlemen, currently no other questions.

Before we say goodbye, I think there is one more comment that John Vollmer would like to make about pretty technical area of our business.

Yeah, one question that didn't come up that I think people trying to do projections would want to be aware of it. Tax rate wise, or expected tax rate to be a little bit higher in 2008 than was in 2007 and our current estimate would be about 35.5%. Unless you might want to consider that as your working through your estimates. That's all I have.

Thanks, John. Again we thank all of our employees. We thank all of our investors. And we look forward to speaking with you at the end of the next quarter. Thanks everybody.

Ladies and gentlemen, this does conclude the presentation. You may now disconnect. Thank you very much. Have a great day.