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Patterson-UTI Energy Inc. (NASDAQ:PTEN)

Q4 2009 Earnings Conference Call

February 11, 2010 10:00 am ET

Executives

Jeff Lloyd – Investor Relations

Mark Siegel – Chairman

Douglas Wall – President & Chief Executive Officer

John Vollmer – Senior Vice President Corporate Development, Treasurer & Chief Financial Officer

Analysts

Marshall Adkins – Raymond James

Alan Laws – BMO Capital Markets

[Brian Ulmer] – Macquarie Capital

John Tasdemir – Canaccord Adams

Scott Grueber – Sanford C. Bernstein & Company

Waqar Syed – Macquarie Capital

Arun Jayaram – Credit Suisse

Kurt Hallead – RBC Capital Markets

Joe Hill – Tudor, Pickering, Holt & Co.

David Wilson – Howard Weil Inc.

Geoff Kieburtz – Weeden

Operator

Good day ladies and gentlemen and welcome to the fourth quarter 2009 Patterson-UTI Energy Incorporated Earnings Conference Call. My name is Eva and I will be your operator for today. At this time all participants are in a listen-only mode. We will conduct a question and answer session towards the end of the conference. (Operator Instructions)

I will now like to turn the call over to Mr. Jeff Lloyd on behalf of Patterson-UTI. Please proceed, sir.

Jeff Lloyd

Thank you, Eva. Good morning on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the fourth quarter and year-ended December 31, 2009. Participating in today's call will be Mark Siegel, Chairman, Doug Wall, President and Chief Executive Officer; and John Vollmer, Chief Financial Officer.

Again, just to quickly remind you that statements made in this conference call, which state the company's or management's intentions, belief, 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 deterioration in the global economic environment, 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 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 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 available through the company's website and through the SEC's EDGAR System.

The company undertakes no obligation to publicly update or revise any forward-looking statement. Statements made in this conference call include non–GAAP financial measures. The required reconciliation to GAAP financial measures are included on our website www.patenergy.com and in the companies press release issued prior to this conference call. And now it’s my pleasure to turn the call over to Mark Siegel for some opening remarks, Mark?

Mark Siegel

Thank you Jeff. Good morning and welcome to Patterson-UTI's conference call for the fourth quarter of 2009. I trust 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.

Our plan this morning, is to take a few minutes to review the results for the three and twelve-month periods ending December 31, 2009. We will briefly mention a few of the financial highlights of the just completed quarter and for the year as a whole. I will then turn the call over to Doug Wall, Patterson-UTI's President and CEO, who will make some comments on the results of the individual business operating units.

After Doug's comments on the quarter, I will make a few brief comments on the market outlook. As always, we will be pleased to take your questions following these prepared remarks. To summarize, the company recorded a net loss of $18.2 million or $0.12 per share for the three-month period ended December 31, 2009 compared to net income of $79.5 million or $0.52 per share for the three months ended December 31, 2008.

Revenues for the quarter, excluding revenues of the discontinued fluids business were $214 million, compared to $532 million in the same quarter last year. On a sequential basis, revenues in fourth quarter improved by $54 million as compared to third quarter or 34% and EBITDA increased by $15.8 million or 37%.

For the twelve-month period ended December 31, 2009, the company’s net loss totaled $38.3 million or $0.25 per share, compared to net income of $347 million or $2.23 per share for the 12-months of 2008. Revenues, excluding revenues of the discontinued fluids business were $782 million for the year ended December 31, 2009, compared to $2.1 billion for 2008.

EBITDA for the year totaled $240 million. As you have seen in our press release our earnings this quarter were impacted by a charge of $10.5 million related to the retirement of drilling assets, including 21 rigs from our drilling rig fleet. This write-off is part of an ongoing process of evaluating our entire rig fleet. Rig-by-rig taking into account industry demand and the expected cost to put rigs back to work.

In each case the rig being written-off is one which we do not expect to put back into work given the size, rig immovability, nature of the rig that is the mass substructure draw works et cetera and likely industry demand for rigs of this type. 19 of the 21 rigs were in West Texas and with the exception of one rig, all were under 1000 horsepower. As we’ve emphasized many times, rigs contain multiple components and there is equipment on these 21 rigs, which is valued at $8.7 million, which we will put into spare parts - spare parts inventory to support other operating rigs. We also retired two sub 1000 horsepower rigs earlier in 2009.

On an after-tax basis, these fourth quarter retirements reduced our earnings by a total of $0.05 per share for the quarter. Subsequent to the quarter, and announced in a press release two weeks ago, we have exited the drilling fluids business through our sale of substantially all the assets.

We made the decision to sell this business as we didn’t see a path by which we could readily achieve significant industry leadership in this segment of our business and thus it was not strategic to our future plans. The financial results for the fourth quarter include an after-tax loss of $2.1 million or $0.01 per share from discontinued operations. Excluding these two unusual items, our earnings would have been a net loss of $0.06 per share better than - a better than expected sequential improvement.

Capital expenditures for the quarter were $102 million and $453 million for the year, modestly below our previous forecast of $500 million. I am pleased to say that we ended the year with $50 million in cash and once again no debt. In addition, we expect the net cash proceeds to total $48 million from the January 2010 sale of our drilling and completion fluids business.

We are also expecting tax refunds of approximately a $114 million in the second quarter of 2010. In our core business segments, drilling and pressure pumping, we are encouraged by recent improvement in activity levels. I would now like to turn the call over to Doug, who will further discuss our operations for the quarter.

Douglas Wall

Thanks Mark. I want to make a few comments this morning on the operating divisions results for the quarter and as usual let me with the drilling company. For the quarter ended December 31 2009, the company had an average of 103 drilling rigs operating, including 95 in the U.S. and 8 rigs in Canada. This is a 30-rig increase over the average activity level, we experienced in the third quarter.

The biggest activity gains came from places like the Permian, the Haynesville, other parts of East Texas, the Marcellus and of course Canada. Average revenues for operating day during the fourth quarter were $16,770 compared to 16,800 in the third quarter. This slight decrease is primarily a result of more rigs on the spot market going back to work at lower overall rates.

The rate declines were mostly offset by six new rigs entering the market on term contracts, all of which were above average rates. Average direct costs per operating day were $10,870 for the fourth quarter, compared to $10,630 last quarter. This increase in our cost per day is a result of an increase of activity in Canada where our operating costs are slightly higher and a decrease in standby days in the U.S. Now, let me explain the standby days. The fewer number of standby days with virtually no associated costs has this impact of actually raising our reported daily costs. The activity improvement is continued throughout January as witnessed by our latest monthly rig count for January of a 122 rigs in the U.S., a further improvement of 14 rigs.

Our Canadian market has increased to 14 rigs, an improvement of 4 rigs in January. Currently, we are running a total of a 145 rigs, a 130 in the U.S. and 15 in Canada. During the fourth quarter, we had an average of 33 rigs working under term contracts of varying lengths. We exited Q4 with 36 rigs working under term contracts and based on the contracts currently in place, we expect to average 42 rigs working under term contracts in 2010.

Now, let me give you a little color on our 2009 new build program and expand on the CapEx numbers, Mark mentioned earlier. Capital expenditures in our drilling business amounted to $86.6 million in the fourth quarter, most of which relates to our 2009 new build program. We delivered six new rigs to the marketplace in Q4 for a grand total of 20 new rigs delivered during the year. Of this total, nine rigs were walking rigs, five were our Apex 1500s, and six were our new Apex 1000s, which as you recall were specifically designed for the Marcellus. Two additional rigs from our ’09 program both of which are Apex 1000s are currently in the process of completion and will be delivered shortly.

We’ve been extremely pleased with the startup and the performance of our new rig technology. The record setting drilling and I should say the record-setting moving performance of these rigs has created additional demand for these kinds of rigs and depending on market demand, we expect to build additional rigs of these types in the coming years in a disciplined manner.

We will continue to assess our new build program for 2010 and beyond, based on the developing market for advanced new technology rigs. We have currently committed to build 13 new rigs, including the nine rigs that we have previously deferred. Contract discussions are currently underway with a number of customers on their equipment needs for specific markets.

We are seeing a lot of ongoing interests in our walking rig technology, particularly in markets such as the Marcellus, where we feel we have a market leading position in pad drilling. As I mentioned earlier, we have seen continued growth in the rig count in the first six weeks of 2010. For the first quarter, we now expect our rig count to average a 140 rigs. Although, we have very limited visibility for the second quarter, we anticipate a decline in Canada due to breakup should be offset by additional rigs going back to work in the U.S.

We expect daily drilling margins in the first quarter to be approximately $5600 per day, reflecting a change in mix as more rigs go back to work in the spot market. We have recently seen pricing improvements of varying degrees in all U.S. markets and in all sizes of the rigs. With respect to CapEx in 2010, our current expectation is for approximately $500 million in spending, consistent with the past couple of years.

Currently, we expect to spend that amount as follows: $230 million on 13 new rigs, $130 million from rig upgrades, primarily top drives, $40 million for additional capacity at Universal Well Service, $80 million for maintenance capital for our drilling business, $15 million for E&P expenditures, and $5 million for completing our MIS system implementation conversion.

Turning on to our pressure pumping business, we had another very solid quarter from Universal Well Service. Despite the early on-set of winter weather and the impact of the holiday season, our revenues in the quarter were up 15% sequentially. Revenue for the quarter was $48 million, and average revenue per job increased to $28,540, a new quarterly record for Universal. Although, the number of jobs declined sequentially by 15% this mix shift towards the higher service intensive jobs that I’m talking about multistage horizontal fracs and nitrogen shale fracs, this mix shift continues.

In addition for the first time in quite some time, our traditional business in the Appalachian showed some improvement, with the improved utilization of our traditional fracs and cement crews. But no question, the overall biggest growth we are witnessing is coming from the Marcellus. The number of horizontal fracs we completed in the Marcellus improved in excess of 33% during the quarter, as activity levels ramped up and we were able to achieve higher utilization of our quintuplex frac crews.

In addition, the number of horizontal nitrogen and foam fracs in the h[Author ID1: at Wed Mar 3 17:28:00 2010

]H[Author ID1: at Wed Mar 3 17:28:00 2010

]uron and Chattanooga shales almost doubled over the levels we witnessed in Q3. To give you some perspective on this, the State of Pennsylvania recorded 1640 traditional Appalachian wells in 2009 versus over 4,100 in the prior year, a decline of 60% in the traditional business. On the other hand, 764 Marcellus shale wells were drilled in ’09, up from 74 in 2008, a 10-fold increase.

Although data is not readily available for the other states in the Appalachians, it should be noted that the Lion share of this activity does come from Pennsylvania. Due to the rapid transition to drilling multiple well pads, we now believe there is a pretty good backlog of Marcellus shale wells behind pipe that are waiting for stimulation and other completion work. We expect this trend to continue and to translate into further improved demand for our services in the coming quarters.

Turning to capital, we spent $43 million on new capital equipments for this market during 2009 with the majority of this directed towards upgrading our fracking capabilities, where we added an additional frac spread during the year.

Much of this additional horsepower came on stream late in the second half, we expect to see the full benefit of it in 2010. Our third complete quintuplex frac spread is now on order and will be delivered in the middle of 2010. Training of these additional crews to support the equipments that’s on order is already underway. We want to make sure we maintain our high service quality.

No question, we are very encouraged by the ramp up in activity in the Appalachians, particularly the Marcellus shale. Although, it was a little slower in developing in 2009 than we thought, we believe 2010 we’ll see the rapid expansion in this market. We are very encouraged by our prospects both for Universal and the drilling company, where we now have 16 rigs operating in this market.

As you know, the Universal has been a market leader in the pressure pumping business for years in the Appalachians and with our capital programs over the last couple of years adding new quintuplex fracs spreads and associated equipment, we believe we’re very well positioned to service this growing market.

Let me make a few comments on the E&P business. We saw revenues during the quarter improved slightly up over 5% over the third quarter. Although production volumes were off 8% in crude oil and off 13% in natural gas, these production volume declines were more than offset by price increases, where our average price for oil was up 12% and the average price we’re seeing for natural gas was up 27%.

For the year in total our revenues declined 50% primarily due to the decline in commodity prices, where as you know oil prices were down 41% and natural gas was down 56% year-over-year.

So with those comments, I’ll turn the call back to Mark for some concluding remarks.

Mark Siegel

Thanks, Doug. 2009 was among the most challenging years ever experienced in the drilling industry and certainly the most challenging period in our company’s recent history. In the first part we saw our working rig count in the U.S. decline from approximately 270 rigs in late October 2008 to less than 50 rigs in May 2009, a change of over 80%. Since that time we have seen our rig count in the U.S. improve to 130 rigs and increase of 160%.

Once again we are pleased with how quickly our drilling operations management has been able to respond to the challenging and changing marketplace and activate rigs to meet customer demand. In respect of the second half of 2010, we are seeing cautious optimism on the part of our customers. We use the term cautious optimism to account for the mix of factors that each of our customers is weighing slightly differently. On the one hand optimism about their prospects in conventional, shale and other unconventional plays but secondly their optimism is tempered by uncertainty and respect of commodity prices and the economy in the second half.

Against this backdrop we are pleased to be able to respond to our customers future needs for advanced technology rigs in a thoughtful and balanced manner. We have the ability based on our balance sheet that actually emerged from the last year’s challenges improved and strengthened to build new rigs when and if appropriate. While cautious optimism best describes the second half of 2010, the next couple of months appear quite strong as our customers in the U.S. continue to look forward to putting additional rigs to work.

With the upward direction in the U.S. rig count there appears to be a definite renewal of optimism among our customers in the drilling and pressure pumping industries. I am also pleased to announce today, that the company declared a quarterly cash dividend as common stock of $0.05 per share to be paid on March 30, 2010 to holders of record as of March 15, 2010.

Before we open the call up to questions we would like to once again thank our employees for helping us do a very tough year in our industry. Our continued success is just not possible without their efforts and we wish to recognize each and every one of them. We would also like to thank our former employees of the fluids business and wish them continued success. I think we can all truthfully say we are happy to see 2009 in the rear view mirror and that we hope that 2010 will be a better year for all of us. Thank you.

At this point I’d like to open the call for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from the line of Marshall Adkins with Raymond James. Please proceed.

Marshall Adkins – Raymond James

Good morning, guys. Looks like you’ve recaptured in the last six months of substantial amount of the market share in a lot of different rig categories. Could you give us a little more color on what you are seeing today via the different rig categories i.e. we’re hearing that some of the 1,500 horse power rigs are now getting as high as 20,000 a day again? Is that accurate? And then walk us through kind of the other rig types if you would?

Thank you.

Mark Siegel

Yeah Marshall, I think we’ve seen – there’s been and actually strength in the market in virtually all markets and a lot of people said for a long time that it was only going to be the new advanced technology rigs that – that go back to work. Well interesting enough there is 230 or 240 rigs working in West Texas. There is 130 rigs or so working in South Texas. Virtually every market has seen some strength and I think that proves that we’ve said all along that it’s one, it’s not going to be a particular market and two, it’s not going to be a particular size of rig but necessarily seize only the strength.

Now having said that, I think you’re right but most of the very good quality 1,500 horsepower rigs at least new technology, 1,500 horsepower rigs are back to work. We’ve seen some strength in pricing in those kinds of rigs, but it’s also bled over into virtually all other sizes and types. Now, of course there’s some varying degrees of those price improvements but I would say that generally speaking you’re correct but it’s not just one particular size or type.

Marshall Adkins – Raymond James

Okay. Your term contracts balanced up. I assume those of the APEX rigs. Correct me if I’m wrong on that but also walk us through your economics. What is it costing to build these 1,500 APEX rigs and what kind of returns do you think you’re getting as you get them out the door?

Mark Siegel

Well, two parts of that question let me answer the first one. Actually you are correct Marshall for the most part it is new builds but I would caution you to say it’s not all new builds. We’ve actually signed some term contracts on existing equipment and interesting enough the terms may not be quite as long as a new build, but it does I think point out the strength in certain markets that people see and the fact that some of our customers have been trying to tie up good quality equipment for some period of time. So, I guess having said that I don’t want you to think it’s all new builds that have been the term contracts because we’ve seen a pretty good mix between both.

Marshall Adkins – Raymond James

Right

Mark Siegel

Now on the economics, we are still, we have a new build program for 2010. We have continued to try to look for term contracts for all of those new builds. Some of them are not coming out until middle part and later this year. We have not been in a huge rush to get things tied up immediately. We’re still sticking to our disciplined approach to trying to get decent terms both pricing and the term of the contract and probably for competitive reasons, we’re not going to divulge to those numbers but I will say this, the term contracts that we have signed were very pleased with the ultimate returns we’re getting on that equipment and those over the life of those term contracts.

Marshall Adkins – Raymond James

Let me just drill down a little more on that, no pun intended. Are we getting anywhere close to the $10,000 margin rate where we were couple of years ago? Or is that just not going to happen?

Mark Siegel

Marsh I think we’re going to pass on getting much more details on that answer quite frankly.

Marshall Adkins – Raymond James

How come I knew that was coming? All right. Last one. Let's see, I had – oh, one last quick one. Regionally, are you I know the 1,000 horsepower APEX rigs are going to the Marcellus, but any specific region that's demanding a lot more of these than others?

Douglas Wall

I think the two biggest growth areas for term contracts, certainly have been sort of Haynesville and the Marcellus, obviously Bakken, but those are about the three strongest markets in terms of term contract type work. We are seeing a little bit of that developed in some parts of South Texas with the Eagle Ford, but there’s obviously some difference in, we are not getting a whole lot of request for term contracts in West Texas and those that we are I think operators are just trying to get rigs tied up at very, very low prices, which we’re not all that interested in.

Marshall Adkins – Raymond James

Great job, guys. Thanks.

Operator

Your next question comes from the line of Alan Laws, with BMO Capital Markets. Please proceed sir.

Alan Laws – BMO Capital Markets

Good morning

Mark Siegel

Hi Alan.

Douglas Wall

Hi Alan

Alan Laws – BMO Capital Markets

Hey I have a question about the decision to reactivate a rig that's been parked for a bit, and you’re going to hire all the crews and so on and so forth. What are the parameters that you're using to bring that rig back active today?

Douglas Wall

Well I think the biggest one Alan is probably length of the commitment from the operator. I mean if an operator just comes and says he’s got one eight-day well in the Barnett, where we look very seriously doesn’t really make sense for us to go get the crews, get them trained, get them back familiar with the rigs, spend whatever money we have to on the rigs. So, we are looking for something that’s multiple wells, may not have to be a term commitment, but certainly the length of the commitment their operators are making to us is a big part of that decision today. Pricing obviously is a big factor.

We’re not in business for the practice. We’ve had plenty of practice over the years drilling wells. So, we’re as a market leader in this business, we do need to get pricing up and margins back up. I think the market swung probably too far the other way for quite some period of time last summer and we’re certainly trying to push it in a different direction.

Alan Laws – BMO Capital Markets

Okay. My second question is at the beginning, when we started to see the rig count pickup, you guys had a very large or oversized share of the incremental rigs coming back to work. Is that because you had more go down because they were in the spot market or is the demand profile out there fitting nicely with your fleet? And, I guess, to finish that off, are you seeing the same type of share gains now?

Douglas Wall

Alan I think, you kind of answered that. I think it’s both of those things. One, there’s no questions on the spot market, our rigs went down quicker and quite honestly some of our operators and our customers were, told us and I think I believe this. They were very concerned about having to let us go because in lot of cases they told us we had the best performing rigs in their fleet, but because we didn’t have a term contract commitment to us they were forced to use somebody else. So I think in some case we’ve seen some of that work in the reverse that some of customers felt, some obligation to get us back because of the performance in the rigs. So, I think that’s helped us. I think today we are still seeing a little bit of that.

Alan Laws – BMO Capital Markets

Great. Last thing is, as far as customer mix, can you maybe give us a little overview of who’s been active through the fall, and is the changing mix from smaller to larger players having any effect at all on your decisions to reactivate any rigs?

Douglas Wall

No, not really and that again depends by market. The West Texas, the mix of customers really hasn’t changed and I think the strength that you see out there it’s our usual mix of customers. So, virtually every market is slightly different, places like the Haynesville and the Marcellus are obviously dominated by a number of customers. We have been very, very good relationships and do very good work for a number of them. I think that’s helped us. We are well positioned I think and virtually all of those resource plays and I think the other thing that certainly really helped us is that our new technology walking rigs really have delivered performance in the marketplace and that’s helped us gain share.

Alan Laws – BMO Capital Markets

Excellent. Last quick one. You want to fathom a guess as how high your rig count can get this year?

Douglas Wall

No, I was hoping you were jealous Alan.

Alan Laws – BMO Capital Markets

I think it’s going a lot higher. I’ll leave with that. Thank you.

Douglas Wall

Thanks.

Operator

Your next question comes from the line of Brian Ulmer with Macquarie Capital. Please proceed, sir.

Mark Siegel

Hello?

Brian Ulmer – Macquarie Capital

Hello. Yeah, yeah this is Brian Ulmer, I'm not sure what firm she said. That's what threw me off. I had a couple of quick questions to ask you, primarily about who are your main customers are. We're seeing a lot of the big large cap guys put rigs back to work. What are you seeing from the private operators? Are they starting to step up with their inquiries, or the contracting?

Douglas Wall

Well, Brian, with the fleet that we have and the fact that we operate in most markets across the U.S. We have a very broad mix of customers. So by market for example, West Texas we have probably 200 different customers that we work for out in those markets. And yes, a lot of them with commodity prices having firmed up, a lot of them have got back to work in other markets like the Barnett and Marcellus and Haynesville, you know who the players are in those markets. We have very good relationships, I think with most of those and so I think by market, we probably have four or five customers that each are operating sort of 10 to 12 drilling rigs a day. And it's just based on performance and based on things that we’ve done having longstanding relationships, they continue to work with us.

Brian Ulmer – Macquarie Capital

Okay. I guess my second question is a little bit unrelated, but when we're talking about the Marcellus and increasing market share up there, are you looking to add capacity either through acquisitions or through new builds?

Douglas Wall

Yeah I think, you will continue to see a number of the new builds that we are already have committed for 2010, well again be heading in that market. We are also looking at some other equipment moving into that market that’s from our what I’m going to call the legacy fleet to satisfied needs of existing customers.

Brian Ulmer – Macquarie Capital

Okay, did you - I have to look at the transcript, but you said you were adding one spread up there now?

Douglas Wall

Well, we are adding one Quintuplex fracs spread in the pressure pumping business.

Brian Ulmer – Macquarie Capital

Okay. I will turn it back over, thanks for your help.

Operator

Your next comes from the line of John Tasdemir with Canaccord Adams. Please proceed.

John Tasdemir – Canaccord Adams

Yeah. Hey, guys. Thanks for taking the call. A couple of quick ones. First, of the 21 rigs you're retiring, or you scrapped, were those 21 rigs - did they work in the peak of 2008?

Douglas Wall

I don’t have the exact numbers in front of me, but virtually all of the rigs that we had in our fleet worked in the last 18 months, but that is, we go through an ongoing process of evaluating the fleet looking at when the last work is really only one component of that. We look at the safety of the equipment in some cases, some of these rigs. And as Mark mentioned 20 of these rigs, I think were in West Texas. Many of these rigs have drilled millions and millions of fleet of hauls over the years and you get to a point where you look at it and say, do we really want to spend that kind of money to refurnish it, or do we really decide to, in essence take some of this equipment and marry it with other equipment and make a better rig somewhere else. So lot of it is an economic decision, in terms of do you really at some point in time, do you take the rig out of the market as opposed to spending a whole lot of money on trying to refurbish it through a condition that will work.

John Tasdemir – Canaccord Adams

Right now, I hear you. And I guess my question really was around was that true capacity coming out of the market. It sounds like it absolutely was true capacity coming out of the market?

Douglas Wall

Yeah

John Tasdemir – Canaccord Adams

The next question quickly is, you said you're going to spend a bunch of money on some top drives. How many rigs will you have by the end of the program that have top drives on them? And is that a good thing for me to look at, in terms kind of trying to identify the rigs that are higher quality? I don't know if that's --

Douglas Wall

Yep. If you take the top drives that we currently have on order and you know maybe sitting ready to be deployed. We'll end the year somewhere between 110 and 120 top drives in the fleet.

John Tasdemir – Canaccord Adams

Would you take a guess, and say that the rigs with top drives are or you have a particular utilization versus rigs without top drives?

Douglas Wall

Well our top drives are movable from rig to rig in most cases, it's not just a quick fix, but we do move them around and for example there is lots of markets where top drives are not needed. You don’t see a whole lot of top drives working in West Texas. You know, so we don’t, we tracked utilization as a top drives. We don’t necessarily track utilization of a rig that’s maybe assigned to a top drive.

John Tasdemir – Canaccord Adams

Well, would you say that your utilization – the utilization of your top drives is 80 plus percent or something like that?

Douglas Wall

Probably closer to 100.

John Tasdemir – Canaccord Adams

Okay. So essentially, you've got 120 top drives. We can imagine that, you've got 120 rigs that should be turning to the right?

Douglas Wall

Well, we certainly hope so.

John Tasdemir – Canaccord Adams

Yeah okay, and I just wanted to triangulate that little bit.

Douglas Wall

Okay

John Tasdemir – Canaccord Adams

Secondly, or thirdly, I think you said you have 13 new rigs going out in 2010. Nine of them are being delivered - are being built on the existing kind of contracts that were set up. I think that leaves another four rigs that are going to be built in 2010. Did you say, did those have contracts already, or are those - I don't know how much talked about that. Are those long-term contracts? Or what's the story behind those four?

Douglas Wall

Well out of the 13 rigs today, we have 5 that are contracted already. I anticipate, certainly we are very hopeful that by the time those rigs are ready and go to field, we will have contracts for most of them, but irrespective of that, we’re prepared to build them regardless, and we think we will hit a growing need in the market, we’ve very clearly trying to build these for markets where we think there is going to be additional demand.

John Tasdemir – Canaccord Adams

Gotcha. Okay, that's helpful. And one last thing. You guys are putting more money into the pressure pumping business, which looks like a solid business line there. I think $40 million you'll spend, adding another spread into the Marcellus. Can you give us 60 seconds on your strategy for the pressure pumping business? Is that something you want to continue to put your shoulder behind, or how do we see that developing for you guys?

Douglas Wall

Well, we think we’ve developed a very niche in that marketplace, and as it's turned out, it's – its been a very growing market, so there is probably more work in the Marcellus than we can handle by ourselves, we’ve been trying to very discipline manner make sure that we maintain our share and maintain our service quality in that market, as you know a number of other competitors have moved into the market, and certainly, we can't keep them out of there. But we are – we're going try to win more than our share of business up there by providing quality service, getting the jobs done and making sure that we're competitively priced.

Mark Siegel

John, it's Mark, just add one thought to what Doug said. We see that business, our well stimulation business a universal as a sort of second core business and it's important for you to recognize that, we see ourselves as having two core businesses, drilling and pressure pumping.

John Vollmer

Hey John, it's John Vollmer. When – in triangulating top drives, I just want to make sure, we didn't get a slight misunderstanding there. Doug was speaking to the top drivers that we're adding currently in addition to what we have. I don’t have precise numbers here in front of me, but I suspect that right now the 130 rigs running in the U.S. somewhere around 70 to 75 would have top drives and the remaining 55 or 60 would not, it's not a 120 of our 130 right now are running with top drives.

John Tasdemir – Canaccord Adams

Right, it sounded like that’s with the additions but yeah, that’s very helpful guys. I appreciate it.

John Vollmer

Yes

Douglas Wall

And I think it is – to want to add one other thing, customers do rent top drives on their own periodically. They may drill a well that doesn’t need it the next well they have they do so they go rent one.

John Tasdemir – Canaccord Adams

I see.

Douglas Wall

So in fact at any point in time we may have more top drives, we not only do we have our own but we have some rental ones that are on some rigs.

John Tasdemir – Canaccord Adams

Okay, thanks.

Operator

Your next question comes from the line of Scott Grueber with Bernstein. Please proceed.

Scott Grueber – Sanford C. Bernstein & Company

Yes, good morning gentleman.

Douglas Wall

Hi Scott

Scott Grueber – Sanford C. Bernstein & Company, Inc.

You mentioned the dispersion in demand across your rig fleet, but at the same time you and have restarted new build programs. So I’m just trying to reconcile the two. Are operators passing up idled rigs – idled upgraded high quality rigs for new build even if they have to pay a premium? Or all of these incremental new builds heading into the deep shale basins where the upgraded rigs are less competitive?

Mark Siegel

Scott, I guess, I would answer that question by saying, I think that the new build rigs are addressing the customers perceived needs for certain kinds of rigs for certain kinds of applications and what they are saying effectively is, “look for this particular well or wells, we want this kind of rig.” And you know some of these are for example, are walking rigs that we built five, six, seven years ago. So there is a real mix here of different kinds of wells and I've likened this to the airline business in which I’ve said there is a number of different planes and each plane is particularly fit for its particular purpose. And that, in effect we’re seeing obviously a greater number of shale plays currently this is a, obviously that a new direction that has emerged in the ever greater share of the U.S. drilling programs. And so for some of those particular wells, the operators are looking for the advanced technology rigs, but as the sort of demand that grew across the Board, there were different rigs fit for different purposes throughout and that was kind of the point Doug made when he mentioned, the significant growth in number of rigs running both in West and South Texas. So I hope that helps.

Scott Grueber – Sanford C. Bernstein & Company, Inc.

That is helpful. So you are seeing the new build added across the number of shale plays though?

Douglas Wall

Yes, There’s interest in lot of different places.

Scott Grueber – Sanford C. Bernstein & Company, Inc.

Okay, that’s helpful. And one final question if I could. You may have mentioned this but is pricing improving for your pressure pumping fleet in Appalachia?

Douglas Wall

Well, let me put it this way. I may not go quite so far as to say it’s improving. I think pricing up there has stabilized, and I think one of the things that’s helped stabilize that is some of our competitors that had come in with predatory pricing have actually learned the hard way that those kind of wells up there are very hard on equipment. And, people that came in to buy their way into market share, I think have found out that, they’re not willing to write a check to maintain that market share. So yes, I think the combination of things, I think pricing – people have now come back to us and said, your pricing was too high, but at least you got the job done. So I think pricing is really starting to firm up in that market, particularly when you’re drilling – and drilling and trying to complete some of these very critical fracs.

Scott Grueber – Sanford C. Bernstein & Company, Inc.

Okay. Great thanks. I will turn it back.

Operator

Your next question comes from the line of Waqar Syed with Macquarie Capital. Please proceed.

Waqar Syed – Macquarie Capital

Good morning. Couple of questions on pressure pumping again. Could you provide us with a number of, what’s your total horsepower that you won in Appalachia?

Douglas Wall

Well, currently, Waqar, it’s about a 132,000 horsepower that’s our current number with the other frac spread and some other things we will be doing, you can probably add another 25,000 horsepower that we plan to add during this coming year.

Waqar Syed – Macquarie Capital

Okay, great. Secondly, could you also provide us the schedule of deliveries for your new builds in 2010?

Douglas Wall

Well, let me just say that roughly and these numbers are – will roughly be probably four rigs in Q1, four in Q4, and the middle part of the year is probably equal at about six per quarter, now those could change slightly. I think the first quarter here very likely we may only get three rigs delivered, but it’s just a matter of a month end thing.

Waqar Syed – Macquarie Capital

To hear it correctly, so four in the first quarter, four in the last quarter, that’s eight and then 12 in the middle. So that - wouldn’t that take you to 20?

Douglas Wall

Well, pardon me here. We’ve also got two rigs that were left over from our ’09 program…

Waqar Syed – Macquarie Capital

Okay.

Douglas Wall

And actually, what I’m quoting you also is a couple of refurbed rigs that – I’m sorry really aren’t new, but are more of a haircut on a rig.

Waqar Syed – Macquarie Capital

Okay.

Douglas Wall

I think, if you just took the 13 new builds, I think you can pretty much equally spread them over the year between quarters.

Waqar Syed – Macquarie Capital

Okay. That’s fair.

Douglas Wall

Two, three and four..

Waqar Syed – Macquarie Capital

Sure, okay. And then on the term contracts you mentioned I believe 45 term contracts, could you also just provide us with information on a quarterly basis, how does that shake out, how many term contracts in Q1 and going through to Q4?

Douglas Wall

I really don’t have that data in front of me. I think we’ll have to stick with the data that we gave you in the script. If that’s something you really need maybe call John offline, we can see if he can give you a little more detail.

Waqar Syed – Macquarie Capital

Sure, sure, we can do that. Thank you very much. That’s all I have.

Operator

Your next question comes from the line of Arun Jayaram with Credit Suisse. Please proceed sir.

Arun Jayaram – Credit Suisse

Good morning.

Douglas Wall

Good morning.

Arun Jayaram – Credit Suisse

John, Mark it was good seeing you last week.

Mark Siegel

A quite.

Arun Jayaram – Credit Suisse

I wanted to get some detail as to help frame, the earnings power pressure pumping in 2010. You did about $48 million in revenue from here, so if you analyze that, it’s just a little over a $190 million. Based on capacity increases and what you’re seeing in the marketplace, you think you can do $220 million in revenue, in pumping in ’10?

Mark Siegel

Well, if you are asking about capability it’s one thing. If you’re asking for us to make a prediction, it’s another. So, if you’re asking for the capability, we’ll say we’ve got the ability to do it, but we’re not going to try and make a prediction beyond and even perhaps more of it, but we’re not going to make prediction about anything past this first quarter.

Douglas Wall

I think, Arun, with the third frac spread, our capability is probably substantially higher than that.

Arun Jayaram – Credit Suisse

Okay. But you would anticipate, you’re adding capacity that it had some pretty nice uptick versus what you did in Q4, is that fair?

Douglas Wall

If the market demand is there and we are competitive, I agree.

Arun Jayaram – Credit Suisse

Okay. That’s fair enough. Second question, you gave us some, guidance in terms of your Q1 margins in the land segment. I’m thinking that implies about a $750 increase per rig day that in the spot market, is that about what you are seeing Q1 versus Q4?

Mark Siegel

John?

John Vollmer

No, I don’t – I am not sure how you are getting there, Arun. I don’t think that we’re anticipating that much increase. We’ve seen some reason, beyond firming up pricing, actual increases well below, but I think we’re anticipating that, the margins are actually slightly lower in the first quarter than the fourth.

Arun Jayaram – Credit Suisse

I am just talking about the spot market, excluding term contracts?

John Vollmer

We are not anticipating that much of an increase in the quarter.

Arun Jayaram – Credit Suisse

Okay. Perhaps, we could discuss that offline. And John, can you give us a little bit help on Q1 guidance for G&A depreciation in the tax rate?

Mark Siegel

Yeah, Arun, I guess that the reason that Doug, John and I are kind of scratching our heads here, is as you know, margin is a mix between the spot rate and the term contract rate and the number of rigs in each category.

Arun Jayaram – Credit Suisse

Right.

Mark Siegel

Percentages. And we’re sitting here, I think quickly looking at each other, trying to figure out what exactly is that mix that got you that number. And we’re all saying to ourselves, we don’t have a quick calculation it’s getting that same number, so rather than try to go through each element of it, I think that we are likely to mislead more people than we really helped, so that’s why you’re getting that sound over the call, it sounds so we don’t know, how you got there.

Arun Jayaram – Credit Suisse

Okay. We can discuss that, offline?

Mark Siegel

Yeah, going back to G&A and that other question, Doug or John?

John Vollmer

Yeah, with the continuation of the CapEx program as described previously, probably driven by timing, but we would expect depreciation will move up $2.5 million to $3 million per quarter as the year progresses, which would take us somewhere toward $315 million to $320 million a depreciation for the year. G&A wise, we get – if you’re looking at with discontinued operations removed, we get some G&A help there. But taken the year in total, I would guess somewhere, towards $60 million. Tax rate, our current estimate would be around 36%.

Arun Jayaram – Credit Suisse

Okay. And the last question is can you just give us, I mean that was a nice tax benefit you're getting, you’ve said in the second quarter just – can you just describe what the source of that was?

John Vollmer

Yeah. Basically, in this business and we're probably not the only ones in the situation, Arun. The fixed assets that we've been adding depreciate very quickly for tax purposes. And so, with a book loss you find yourself with a even bigger tax NOL and those dollars can be carried back or carried forward. And that is a nature of the savings. It's taken a tax NOL and carrying it back.

Arun Jayaram – Credit Suisse

Okay. Thanks a lot guys.

John Vollmer

The taxes.

Operator

Your next question comes from the line of Kurt Hallead with RBC Capital Markets. Please proceed sir.

Kurt Hallead – RBC Capital Markets

Thanks. Hey, good morning.

Mark Siegel

Good morning, Kurt. How are you?

Kurt Hallead – RBC Capital Markets

I’m doing fine. How are you guys doing?

Mark Siegel

Good, well.

Kurt Hallead – RBC Capital Markets

Excellent. When you looking at some of the price increases that you are getting now for the land rigs. Can you talk to us about what kind of flows through you’re getting on that pricing? How much is being in a way by cost increases, if any or are you getting paid for MOB, or you getting paid for fuel. So, I just want one of you if you could give us some more color of the flow through on the pricing.

Mark Siegel

Yeah, Kurt, yeah we’ve really been getting paid for fuel throughout. I think it’s been a number of years, since we haven’t been paid for fuel. And in terms of mobilization, I don’t think we’ve had to significantly discount that either. What would you add to that Doug?

Douglas Wall

Yeah, I think, Kurt as I mentioned, we’re getting varying degrees of price improvement by market. I mean I won’t, we wish we were getting higher increases in West Texas, they tend to be in the 250 to 500 to 750 a day. It’s a little harder to get price to move in that market, where you got a substantial overcapacity of equipment. But, the other end of the extreme is in the advanced technology 1,500 horsepower rigs, we’re seeing some very nice improvements just because of the limited number of those rigs in the marketplace.

Kurt Hallead – RBC Capital Markets

Now, the last time I heard the price improvement ranges were anywhere between $100 to a $1000 a day. Is that piece of pricing plateauing or is that accelerating?

Douglas Wall

Well, we never use the P word here. So, I think it’s remained and that’s – I would say the numbers are little higher than what you quoted, depending on the marketplace. It’s a very broad range, Kurt, depending on which market for which rig. And so, that the hesitancy is sort of to pin a specific number on rigs across the broad range.

Kurt Hallead – RBC Capital Markets

What about the pace of – now once again I know you don’t may not want to use the word pace rig, but nonetheless, what is the – is it accelerating or plateauing, the rate of change on pricing accelerating or plateauing?

Douglas Wall

I would say it’s stayed fairly constant here throughout the last 60 days, but those conversations are taking place everyday with virtually every customer.

Kurt Hallead – RBC Capital Markets

Okay. Now, the other thing that caught my attention here was your comment about pressure pumping, pricing in Appalachia stabilizing, some indications that we’re getting from the field, is that there are, shortages of pressure pumping equipment in the Marcellus and wait times are developing, which indicates to me that pricing is actually on the rise. So, I just was hoping you might be able to help me clarify that?

John Vollmer

Kurt, marketwise I suspect that’s probably true, but keep in mind as indicated earlier, we did not cut pricing in pressure pumping, the way some others did. We maintained I think better margins than others during the 2009 time period. So, to say that pricing is moving up, I think it’s probably fair. I think, we started at higher pricing than others. Would you agree, Doug?

Douglas Wall

No question.

Kurt Hallead – RBC Capital Markets

Okay. And then if I miss this I apologize. You gave some reference points on what you expect to see happen in the first quarter with the drilling business. So, on your pressure pumping business, first quarter revenue up versus fourth quarter, I would imagine given the significant increase we’ve seen in overall activity?

Douglas Wall

Yeah, I think we will see some increase in the first quarter on pressure pumping, yes.

Kurt Hallead – RBC Capital Markets

And then you should probably get some improvement on margins on top of that, right?

Douglas Wall

Unclear whether we will see an increase in the first quarter on margins, we could get a little bit.

Kurt Hallead – RBC Capital Markets

Okay. So, you guys are clearly on in process of continuing to deliver to the market what they need in terms of new rig technology. You guys still have zero debt and a lot of firepower to continue to increase your share in that market segment. Can you update us on how you plan to use the balance sheet? And I know you guys have always been very debt adverse, but there is a difference between being debt adverse and using a little bit of leverage to improve your market position, so I just wonder if you could give me some update on that?

Mark Siegel

Kurt, I will try. Frankly, as people who John and I’ve been working together for, I think plus 20 years, and we started out in the leverage buyout business. And as you know, UTI started and Patterson both started out with substantial amounts of debt. So calling us debt adverse I think is probably a tail that this donkey doesn't particularly want to wear, but I think our view has been that we’ll take on debt when we think it’s useful and necessary. With this year's CapEx program current, projections we think we will probably use some debt during this year. So there is an expectation of having some debt. We're not adversed[Author ID1: at Wed Mar 3 17:30:00 2010

]adverse[Author ID1: at Wed Mar 3 17:30:00 2010

] to taking on debt for the right opportunities. As you heard from both us the script, as well as the answer is we do intend to complete two rigs from last year's building program, 13-additional rigs, which we've talked about in the prior conversation. So we're putting rigs back into the field – new rigs into the field. To meet the demand, we think that there is and we think that we continue to benefit by sort of picking between certain spot market opportunities and certain term market opportunities.

Kurt Hallead – RBC Capital Markets

Okay. Now, for your pressure pumping business, do you think your growth vehicle is mainly going to be organic or is there some M&A that’s still yet to happen?

Mark Siegel

We’re always looking for M&A opportunities. I mean, if I would tell you there was anything about 2009 that surprised us, and I think this is true both in the oil services industry, as well as sort of across the Board. It was that in effect certain things that had debt found themselves with equity bailouts, and so it was difficult for buyers to be able to achieve acquisitions at acceptable prices. And so we’ve looked at a bunch of things over the past 24 months trying to cease something that would really add value to our existing shareholders. We haven’t found it.

Kurt Hallead – RBC Capital Markets

So it’s still better to build than buy, is the answer, right?

Mark Siegel

Correct.

Kurt Hallead – RBC Capital Markets

Okay. And then lastly, on your return hurdles, can you give us some general bench marks as to what your return hurdles are when you are looking at, your new build program for land rigs, weighted average, cost of capital 12%, 10%, but what kind of return hurdles are you looking at?

Mark Siegel

Kurt, I guess I would say that, Im[Author ID1: at Wed Mar 3 17:30:00 2010

]I’m[Author ID1: at Wed Mar 3 17:30:00 2010

] kind of old school, and I like to get 20% returns on plans that we have to deploy capital. So that’s what I, when we start a project, we are looking for that as an objective.

Kurt Hallead – RBC Capital Markets

Okay. And these term contracts on existing equipment, are they coming in at least 12 months or longer or less than that?

Douglas Wall

Well, 12 months is the minimum, Kurt. About half the ones we've already signed up are three years and there is a couple I think in place today that are one year.

Kurt Hallead – RBC Capital Markets

Okay, great. Thanks guys.

Operator

Your next question comes from the line of Joe Hill with Tudor Pickering. Please proceed.

Joe Hill – Tudor, Pickering, Holt & Co.

Good morning.

Mark Siegel

Hi, Joe.

Douglas Wall

Hi, Joe.

Joe Hill – Tudor, Pickering, Holt & Co.

Hey, guys, most of my questions have been touched on, but I just wanted to get some clarification surrounding crewing and the ability to get employees and whatnot. What's the current headcount in the drilling company today?

Douglas Wall

Oh, Joe, I don’t have that exact number, it’s plus or minus 3,700 employees.

Joe Hill – Tudor, Pickering, Holt & Co.

Okay. And I am thinking around 20, 21 employees per rig.

Douglas Wall

Probably a little higher than that, but probably a good number to use.

Joe Hill – Tudor, Pickering, Holt & Co.

Okay. Doug, how many rigs do you think you can provision today given your current staffing levels?

Douglas Wall

Well, Joe currently we don’t keep a whole lot of extra people around, but obviously, we keep very close tabs between marketing and operations, and as we expect the rigs to go up. In most cases, we have, a week to 10 days to two weeks advance notice of when a rig is going to go back up to work. And to-date, we’ve had a little or no problem getting people back on crews. And I don’t anticipate that’s going to be a problem really for quite some time.

Joe Hill – Tudor, Pickering, Holt & Co.

Okay. So you only need about a week to 10 days to mobilize a crew from scratch?

Douglas Wall

Most of these people are our people that have worked for us before. They maybe partially or currently working on other rigs. As we shrunk, we kept the key people and had them basically a driller might have been working derrick or motor hand. So a lot of these people are just maybe going back to their original rig. So it’s really a roughnecks and primarily and motor hands that we’re hiring at the moment and like I say, we’ve got a pretty good advanced pool. Trust me; we are still getting lots of calls everyday and every region of people looking for work.

Joe Hill – Tudor, Pickering, Holt & Co.

Okay. So if I told you that I was expecting your rig count to exit the year at, say, 200, would you view that as a level that would be easily achievable from a crewing standpoint?

Douglas Wall

Well, I don’t know if it'd be, it's always hard work, it's not easy, but given enough time, it depends on the jump and how quickly. can we put out so many rigs per month? Yes, if the number is 10 or 20 rigs, fair enough. But if we tried to put out 50 or 60 rigs in a month that becomes much more of a problem.

Joe Hill – Tudor, Pickering, Holt & Co.

Okay. Thank you very much.

John Vollmer

One other clarifying point the 3,700 roughly employees. Please don’t view that as a 175 rigs or the people, we have the yards, we have rig construction, we transport our own rigs. The 3,700 factors in all of those employees. I don’t think, we carry frankly, any amount of extra employees over the rigs, we're running currently, or those we're activating at a given moment in time.

Douglas Wall

Joe, one of the things you should know is that, with the new build rig program and even with refurb rig program and I know I kind of confuse those two things on an earlier question. But, we typically the people that build the rig, are typically the people that take it to the field. So with virtually all of those new builds, we’ve already got the crews there, they’re putting the rig together before it even goes to the field.

Joe Hill – Tudor, Pickering, Holt & Co.

Okay, thanks for the clarification.

Operator

Your next question comes from the line of Alan Laws with BMO Capital Markets. Please proceed sir.

Alan Laws – BMO Capital Markets

Thanks for getting me in again, guys. Just a couple of quick follow up questions. First, I think I might have missed this. But do the 13 rigs that you’re building do they have contracts?

Douglas Wall

Currently, Alan about five of those 13 have term contracts.

Alan Laws – BMO Capital Markets

Okay, cool. And the other one was, this is a follow-up to Kurt's question on the M&A side, you mentioned you look at the business as two parts now, just the pumping business and the drilling business. Do you have a preference out there, or do you have a preference out there for where you may lean in terms of M&A? Would you rather be bigger in Universal, or would you like, say, the Rowan rigs?

Mark Siegel

Well, I’m not going to speak any specific acquisition as you – I’m sure you expected.

Alan Laws – BMO Capital Markets

All right.

Mark Siegel

We see both business is a core businesses and there is – I don’t think any felt leaning towards doing M&A and one is opposed to the other. We think of them as two of our beloved children, and we wanted to take good care of both of them.

Alan Laws – BMO Capital Markets

Nice answer, I like that. Thanks.

Operator

Your next question comes from the line of Dave Wilson with Howard Weil. Please proceed.

David Wilson – Howard Weil Inc.

Good morning, guys. Real quick question. In your release you mentioned Canada as a reason for operating costs going forward, and I know the activity in the first quarter looks to be strong. Is that a reason for the margins, overall margins to be headed down sequentially? In other words, is it possible for you to break out for us the U.S. versus Canada fourth quarter versus first quarter kind of margin breakout?

Mark Siegel

I do not have that with me Dave. The thing it goes on in Canada is the margins are a little bit lower there, the costs are higher and that does affect the average cost in the fourth and the first quarter when you’re running so many rigs in Canada. And that was what that we’ll take down as well.

Douglas Wall

Yeah. Our labor cost in Canada, in particular are much higher than they are in the U.S.

David Wilson – Howard Weil Inc.

So in that regard, do you expect like second quarter for as the rig count in Canada comes down for the margins to increase then?

Mark Siegel

That would result in cost per day decreasing some driven by the mix there. To say that margins will go up because we run less rigs in Canada, I don’t know that I would say that.

David Wilson – Howard Weil Inc.

All right. Fair enough. Thank guys.

Mark Siegel

If the margin differential in particularly in the first quarter is not a big margin differential, it’s small.

David Wilson – Howard Weil Inc.

Okay. Thank you.

Operator

Your next question comes from the line of Geoff Kieburtz with Weeden. Please proceed sir.

Geoff Kieburtz – Weeden

Thanks. Good morning.

Douglas Wall

Hi Geoff.

Geoff Kieburtz – Weeden

A couple of questions. Versus last quarter, you’re looking at 42 rigs on term contracts in 2010 compared to 34, 90 days ago. And then just five more rigs in 2011. So can I back into a conclusion that you got three rigs that you've added that are on one-year contracts and at least five that have been added that are at least two-year contracts?

Unidentified Company Representative

I think generally that’s probably correct. When we give you those term contracts that’s only what we know today.

Geoff Kieburtz – Weeden

Right.

Unidentified Company Representative

I fully expect that those numbers will go up. We know what’s coming off term contract in 2010 and it’s not a big number. What we don’t know today is how many more term contracts we may get and I do expect we will get some more.

Geoff Kieburtz – Weeden

I guess what I was trying to get at, is you've signed eight additional term contracts over the last 90 days.

Unidentified Company Representative

Geoff, some of those term contracts over the last 90 days have been three years, some of them one-year. And so there is a mix issue here between different contracts. I’m not going to want to get too specific for again for competitive reasons but there are three-year contracts, which we have signed. There are one-year contracts, which we have singed, and there’s a mix and what we try to do in putting that present release out in respect of rigs under term contracts is look at where we are as of today and say looking forward and doing it literally kind of month-by-month on the spread sheet, how many rigs under contract for how long? And that’s what you’re seeing and backing into it the way you’re doing it. I think you may – you may get a riot for that. I don’t want to be warranting your – the way you’re doing it.

Unidentified Company Representative

Geoff, the other factor there is we have signed term contracts on non-new build rigs, which sometimes confuses the issue.

Geoff Kieburtz – Weeden

Right. I understand. The five new builds that have term contracts out of the 13, did you sign those over the last quarter?

Douglas Wall

Yes

Geoff Kieburtz – Weeden

Okay. That’s what I was, no it’s one of the other things, and those – on all of those term contracts can we assume that they are meeting your 20% IRR target?

Douglas Wall

John you want to

John Vollmer

Interesting question to, I would say I think I would like not to respond to that for...

Geoff Kieburtz – Weeden

Okay. All right, we talked a little bit earlier about your market share gains. Let me use a different reference. Rough calculation at the peak of the U.S. rig count, your market share was around 14%. Today, it's around 10%. Do you have any internal targets for returning to that 14% share gain, and if so, kind of when would you expect to get there?

Douglas Wall

Geoff, we don’t focus or zero in so much on market shares, we do profitability. As you know pricing and market share are kind of two factors where, last time I checked we don’t really get paid on market share. Our shareholders judge us on profitability and return to shareholders. So we watch market share very carefully, but we maybe making more money at 10 or 11% market share than we might at 14. And so we try to balance those two things, but we don’t have any specific goals about strictly going after market share.

Geoff Kieburtz – Weeden

Okay, fair enough. Do you see any reason that given your fleet, what you see today in terms of where the customer demand is, that you can't return to a 14% market share, assuming that the economics justify that expansion?

Douglas Wall

I don’t think there’s any question we could get back there or higher.

Geoff Kieburtz – Weeden

Okay. Alright. And John, a couple of questions. The $3.8 million loss on the asset retirement is called up, but we've got a total $10.5. Where is the – in the income statement, where is the difference between those two?

John Vollmer

The number that’s referred to is actually all in depreciation.

Geoff Kieburtz – Weeden

Okay, alright. So that difference between 10.5 and 3.8 is sort of one-time boost in D&A in the quarter that we shouldn't see repeat.

John Vollmer

I believe the number $10.5 million is the kind of delta in depreciation.

Geoff Kieburtz – Weeden

Okay, so the $10.5 doesn’t include the $3.8 million loss?

John Vollmer

Yeah, that’s correct.

Geoff Kieburtz – Weeden

Okay, alright. And the other income was – it took a big jump up, what’s behind that?

John Vollmer

Other income.

Geoff Kieburtz – Weeden

Yeah.

John Vollmer

Other income above the line or below the line? I think that’s just disposable in assets, I think.

Mark Siegel

Other income above the line. Oh, I know. Let’s talk about – that's recovery on bad debt, I'm sorry. I'm in the wrong place.

John Vollmer

Jeff, did you get that?

Operator

He has left the queue – he left the queue.

Mark Siegel

Okay. Yeah, that's – I'm sorry, it's a recovery on bad debt.

Operator

Okay. With no further questions in the queue, I would now like to turn the call back over to Mr. Mark Siegel for closing remarks. You may proceed, sir.

Mark Siegel

Thank you. We would like to thank all of our investors and analysts for their participation in this call and thank you. Look forward to our next one at the end of our first quarter. Thank you, every body.

Operator

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

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Source: Patterson-UTI Energy Inc. F4Q09 (Qtr End 12/31/09) Earnings Call Transcript
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