Patterson-UTI Energy Inc (PTEN) 2009 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth quarter 2009 Patterson-UTI Energy, Incorporated, earnings conference call. (Operator Instructions) I would now like to turn the call over to Mr. Geoff Lloyd, on behalf of Patterson-UTI. Please proceed, sir.

Thank you, Yvette. 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 a quick reminder that statements made in this conference call which state the Company's or management's intentions, beliefs, expectations or predictions for the future, are forward-looking statements. It'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, 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 he 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. They are -- the required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company's 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.

Thank you, Geoff. 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 12-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 12-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've 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 moveability, nature of the rig, that is the mast, 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 1,000 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 inventory to support other operating rigs. We also retired two sub-1,000 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 of 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 $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'd now like to turn the call over to Doug, who will further discuss our operations for the quarter.

Thanks, Mark.

I want to make a few comments this morning on the operating division's results for the quarter and, as usual, let me start 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 US and eight 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 per 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 cost 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 US.

Now, let me explain the standby days. The fewer number of standby days with virtually no associated costs have this impact of actually raising our reported daily costs. The activity improvement has continued throughout January, as witnessed by our latest monthly rig count for January of 122 rigs in the US, a further improvement of 14 rigs. The Canadian market has increased to 14 rigs, an improvement of four rigs in January. Currently, we are running a total of 145 rigs, 130 in the US, 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 1500, 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 start up 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 had 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 interest 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 140 rigs. Although we have very limited visibility for the second quarter, the anticipated decline in Canada, due to breakup, should be offset by additional rigs going back to work in the US. We expect daily drilling margins in the first quarter to be approximately $5,600 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 US markets and in all sizes of rigs.

With respect to CapEx in 2010, our current expectation is for approximately $500 million in spending, consistent with the past couple years. Currently we expect to spend that amount as follows. $230 million on 13 new rigs, $130 million for 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 now to our pressure pumping business, we had another very solid quarter from Universal Well Service. Despite the early onset 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, and I'm talking about multistage horizontal fracks and nitrogen shale fracks, this mix shift continues. In addition, for the first time in quite some time, our traditional business in the Appalachian showed some improvement, with improved utilization of our traditional frack and cement crews. But, no question, the overall biggest growth we are witnessing is coming from the Marcellus. The number of horizontal fracks 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 frack crews. In addition, the number of horizontal nitrogen and foam fracks in the Huron and Chattanooga shales almost doubled over the levels we witnessed in Q3.

To give you some perspective on this, the state of Pennsylvania recorded 1,640 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 ten-fold increase. Although data is not readily available for the other states in the Appalachians, it should be noted that the lion's share of this activity does come from Pennsylvania. Due to the rapid transition to drilling multiple well pads, we now believe there's 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 equipment for this market during 2009, with the majority of this directed towards upgrading our fracking capabilities, where we added an additional frack 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 frack spread is now on order and will be delivered in the middle of 2010. Training of these additional crews to support the equipment that's on order is already underway. We want to make sure we maintain our high service quality.

No question, we're 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 will 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, Universal's been a market leader in the pressure pumping business for years in the Appalachians. And with our capital programs over the last couple years, adding new quintuplex frack 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 improve 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 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.

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 US 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 US improve to 130 rigs, an 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 in 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 US continue to look forward to putting additional rigs to work. With the upward direction in the US rig count, there appears to be a definite renewal of optimism among our customers in the drilling and pressure pumping industries. I'm also pleased to announce that today, the company declared a quarterly cash dividend in its 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 through a very tough year in our industry. Our continued success is just not possible without their efforts, and we wish 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 rearview 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.

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

Good morning, guys. Looks like you've recaptured, in the last six months, a 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 1500 horsepower rigs are now getting as high as $20,000 a day again. Is that accurate? And then walk us through the other rig types, if you would.

Doug, you want to?

Marshall, I think we've seen, there's been actually strength in the market, in virtually all markets. A lot of people said for a long time that it was only going to be the new advanced technology rigs that go back to work. Well, interesting enough, there's 230 or 240 rigs working in west Texas. There's 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 that necessarily sees only the strength.

Now, having said that, I think you're right that most of the very good quality 1500 horsepower rigs, at least new technology 1500 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, you know, one particular size or type.

Okay. Your term contracts bounced up. I assume those are the APEX rigs. Correct me if I'm wrong on that, but also walk us through your economics. What is it costing to you build these 1500 APEX rigs, and what kind of returns do you think you're getting as you get them out the door?

Well, two parts to that question. Let me answer the first one. Actually, you're 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.

Right.

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 we're probably, for competitive reasons, we're not going to divulge those numbers. But I will say this, the term contracts that we have signed, we're very pleased with the ultimate returns we're getting on that equipment and those -- over the life of those term contracts.

Are we -- 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 a couple years ago? Or is that just not going to happen?

Marshall, I think we're going to pass on getting much more detailed on that answer. Quite frankly--

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

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're seeing is a little bit of that develop in some parts of south Texas with the Eagleford. But, you know, there's obviously some difference in -- we're not getting a whole lot of requests 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.

Great job, guys. Thanks.

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

Good morning. I have a question about a decision to reactivate a rig that's been parked for a bit, and you go 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?

Well, I think the biggest one, Alan, is probably length of the commitment from the operator. If an operator comes and says he's got one eight-day well in the Barnett, we're -- we look very seriously. Does it 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're looking for something that's multiple wells. May not have to be a term commitment, but certainly the length of the commitment the operator is 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.

Okay, my second question is, at the beginning, when we started to he see the rig count pick up, 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?

Alan, I think you kind of answered that. I think it's both of those things. One, there's no question that on the spot market our rigs went down quicker, and quite honestly, some of our operators and our customers told us, and I think I believe this, they were very concerned about having to let us go. Because in a 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 it, they were forced to use somebody else. So I think in some cases, we've seen some of that work in the reverse, that some of our customers felt some obligation to get us back because of the performance of the rigs. So I think that's helped us. I think today we're still seeing a little bit of that.

Great. Last then is, as far as customer mix, can you maybe give us an 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?

No, not really. 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 happen to have very good relationships and do very good work for a number of them. I think that's helped us. We're well positioned, I think, in 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.

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

No, I was hoping you'd tell us, Alan.

I think it's going a lot higher. I'll leave it at that. Thank you.

Your next question comes from the line of [Brian Omare] with (inaudible) Capital. Please proceed, sir.

hello?

Hello.

This is Brian Olmer. 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 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?

Well, Brian, with the fleet that we have and the fact that we operate in most markets across the US, 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 Barnetts and the 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, you know, I think by market, we probably have four or five customers that each are operating sort of 10 to 12 drilling rigs today. And it's just based on performance, and based on things that we've done, having longstanding relationships, they continue to work with us.

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?

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

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

Well, we're adding one quintuplex frack spread in the pressure pumping business.

Okay. I'll turn it back over. Thanks for your help.

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

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?

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's -- we go through an ongoing process of evaluating the fleet, looking at when they last worked 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 feet of hole 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 refurbish it, or do we really decide to, in essence, take some of this equipment and marry with it other equipment and make a better rig somewhere else? So a 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 to a condition that'll work.

No, I hear you. 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.

Yes.

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 of trying to identify the rigs that are higher quality? I don't know if that's --

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

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

Well, our top drives are moveable from rig to rig in most cases. It's not just a quick fix, but we do move them around. And, for example, there's lots of markets where top drives are not needed. You don't see a whole lot of top drives working in west Texas. So we don't -- we track utilization of the top drives. We don't necessarily track utilization of a rig that's maybe assigned to a top drive.

So, would you say that your utilization -- the utilization of your top drives is 80 plus% or something like that?

Probably closer to 100%.

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

Well, we certainly hope so.

Okay. I just wanted to triangulate that a little bit. 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 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? What's the story behind those four?

Well, Well, of the 13 rigs today, we have five that are contracted already. I anticipate, certainly we're 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'll hit a growing need in the market. We've very clearly tried to build these for markets where we think there's going to be additional demand.

Got you. 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?

Well, we think we've developed a very nice niche in that marketplace. And, as it's turned out, it's been a very growing market. There's probably more work in the Marcellus than we can handle by ourselves. We've been trying to very disciplined 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're going to try and 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.

John, it's Mark. Just to add one thought to what Doug said. We see that business, our well stimulation business at 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, it's John Vollmer. One -- In triangulating top drives, I just wanted to make sure we didn't get a slight misunderstanding there. Doug was speaking to the top drives 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, of the 130 rigs running in the US, somewhere around 70 to 75 would have top drives, and the remaining 55 or 60 would not. It's not 120 of our 130 right now are running with top drives.

Right, it sounded like that's with the additions. But yes, that's very helpful, guys. I appreciate it.

And I think, 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.

Ah, I see.

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

Okay. Thanks.

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

Yes. Good morning, gentlemen.

Hi Scott.

You mentioned the dispersion in demand across your rig fleet, but at the same time you and [inaudible] 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 builds, even if they have to pay a premium? Or are all these incremental new builds heading into the deep shale basins, where the upgraded rigs are less competitive?

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.. What they're saying, effectively, is look, for this particular well or wells, we want this kind of rig. And some of these are, for example, our walking rigs that we built five, six, seven years ago. So there's a real mix here of different kinds of wells, and I've likened this to the airline business in which I've said there's 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 an -- obviously a new direction that has emerged in 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 the demand 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.

That is helpful. So, you are seeing the new builds added across a number of shale plays, though.

Yes, there's interest in a lot of different places.

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?

Well, let me put it in the 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 a 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 that in market, particularly when you're drilling and trying to complete some of these very critical fracks.

Okay, great, thanks, I'll turn it back.

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

Good morning. Couple of questions on pressure pumping again. Could you provide us with the number of -- what's your total horsepower that you own in Appalachia?

Well, currently, Waqar, it's about 132,000 horsepower. That's a current number. With the other frack spread and some other things we'll be doing, you can probably add another 25,000 horsepower that we plan to add during this coming year.

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

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.

To hear it correctty, so four in the first quarter, four in the last quarter, that's eight. And then 12 in the middle. Wouldn't that take to you 20?

Oh, pardon me. We've also got two rigs that were left over from our '09 program. 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.

Okay.

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

Okay. That's fair.

Two, three, and four.

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

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, if would you maybe call John off-line. We can see if he can give you a little more detail.

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

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

Good morning.

Hey, Arun.

John, Mark it was good seeing you last week.

Likewise.

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

If you're 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, but we're not going to make a prediction about anything past this first quarter.

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

Okay. But you would anticipate -- you're adding capacity, that you'd have some -- a pretty nice u- tick versus what you did in Q4. Is that fair?

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

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 in the spot market. Is that about what you're seeing, Q1 versus Q4?

John?

No, I don't -- I'm not sure how you're getting there, Arun. I don't think that we're anticipating that much increase. We've seen some recent, beyond firming of pricing, actual increases well to well. But I think we're anticipating that the margin is actually slightly lower in the first quarter than the fourth.

I'm just talking about the spot market, the spot market excluding term contracts.

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

Okay. Perhaps we could discuss that off-line. John, can you give us a little bit of help on Q1 guidance for G and A depreciation in the tax rate?

Arun, I guess 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.

Right.

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 that's getting that same number. So rather than try to go through each element of it, I think that we're likely to mislead more people than we really help. So that's why you're getting that look from -- that sound over the call that sounds as though we don't know how you got there.

Okay. We could discuss that off-line.

Going back to G&A and that other question -- John.

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

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

Yes. 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 quick for tax purposes, and, so you know, 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 the nature of the savings. It's taking a tax NOL and carrying it back.

Okay. Thanks a lot, guys.

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

Thanks. Good morning.

Hey Kurt, how are you?

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

Doing well.

Excellent. When you're looking at some of the price increases that you're getting now for the land rigs, can you talk us -- talk to us about what kind of flow through you're getting on that pricing? How much is being eaten away by cost increases, if any, or are you getting paid for MOB, are you getting paid for fuel? So, I just wonder if you could give us some more color on the floats or on the pricing.

Yes, Kurt. 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?

I think, Kurt, 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 that in market where you've got a substantial overcapacity of equipment. But the other end of the extreme is in the advanced technology, 1500 horsepower rigs. We're seeing some very nice improvements just because of the limited number of those rigs in the marketplace.

Now, the last time I heard the price ranges -- price improvement ranges were anywhere between $100 to $1,000 a day. Is that pace of pricing plateauing, or is it accelerating?

Well, we never use the P word here. I think it's remained in that -- I would say the numbers are a 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 the hesitancy is sort of to pin a specific number on rigs across a broad range.

What about the pace of, once again, I know you may not want to use the word pace, but nonetheless, is it accelerating or plateauing, the rate of change on pricing? Accelerating or plateauing?

I would say it stays fairly constant here throughout the last 60 days. But those conversations are taking place every day with virtually every customer.

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 all indicates to me, 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.

Market-wise, 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 is probably fair. I think we started at higher pricing than others. Would you agree, Doug?

No question.

Okay. And if I missed 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?

Yes, I think we'll see some increase in the first quarter on pressure pumping, yes.

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

Unclear whether we'll see an increase in the firsts quarter on margins. We could get a little bit.

Okay. So you guys are clearly on -- in the 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? I know you guys have always been very debt adverse. But there's a difference between being debt averse, 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.

Kurt, I'll try. Frankly, as people who -- John and I have been working together for, I think plus 20 years, and we started out in the leveraged buyout business. And as you know, in the leveraged buyout business, and as you know, UTI 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 adverse to taking on debt for the right opportunities. As you heard from both the script as well as the answers, we do intend to complete two rigs from last year's building program, 13 additional rigs, which we've talked about in the prior conversations. So we are putting rigs back into the field -- new rigs into the field to meet the demand that we think there is. And we think that we continue to benefit by sort of picking between certain spot market opportunities and certain term market opportunities.

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?

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 see something that would really add value to our existing shareholders. We haven't found it.

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

Correct.

Okay. Then lastly, on your return hurdles, can you give us some general benchmarks as to what your return hurdles are, when you're looking at your new build program for land rigs, weighted average cost of capital, 12%, 10%? What kind of return hurdles are you looking at?

Kurt, I guess I would say that I'm 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're looking for that as an objective.

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

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

Okay, great. Thanks, guys.

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

Good morning.

Hi, Joe.

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?

Joe, I don't have that exact number. It's plus or minus 3,700 employees.

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

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

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

Well, you know, 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 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 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.

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

You know, most of these people are people that have worked for us before. They may be partially -- 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 roughnecks 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're still getting lots of calls every day in every region, of people looking for work.

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?

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, it becomes much more of a problem.

Okay. Thank you very much.

One other clarifying point. The 3,700, roughly, employees, please don't view that as 175 rigs worth of people. We have yards, we have rig construction, we transport our own rigs. The 3,700 factors in all 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.

That's correct. 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 confused 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 those new builds, we've already got the crews. They're putting the rig together before it even goes to the field.

Okay. Thanks for clarification.

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

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?

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

Okay, cool. And the other one was, this is a follow-up to Kurt's question on the M and A side, you mentioned you look at the business as two parts now, 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 and A? Would you rather be bigger in Universal, or would you like, say, the Rowan rigs?

I'm not going to speak to any specific acquisition, as I'm sure you expected. But we see both businesses as core businesses, and there's I don't think any felt leaning towards doing M&A in one as opposed to the other. We think of them as two of our beloved children, and we want to take good care of both of them.

Nice answer. I like that. Thanks.

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

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 US versus Canada fourth quarter versus first quarter margin breakout?

I do not have that with me, Dave. The thing that 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 first quarter when you're run so many rigs in Canada. And that was what that comment was about.

Our labor costs in Canada, in particular, are much higher than they are in the US.

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

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.

All right, fair enough. Thanks, guys.

The margin differential, particularly in the first quarter, is not a big margin differential. It's small.

Okay, thank you.

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

Thanks. Good morning. 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 are on -- 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?

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

Right.

We 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.

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

Geoff, some of those term contracts over the last 90 days have been three years, some have been one year, and so there's a mix issue here between different contracts. I'm not going to want to get too specific for, again, sort of competitive reasons, but there are three-year contracts which we have signed. There are one-year contracts which we have signed, and there's a mix, and what we try to do in putting that press 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 a spreadsheet, how many rigs under contract for how long, and that's what you are seeing, and backing into it the way you're doing it, you may get it right, but I don't want to be warranting the way you're doing it.

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

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

Yes.

Okay. That's what I was -- one of the other things. And those -- on all of those term contracts, can we assume that they are meeting your 20% IRR target?

John, you want to --

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

Okay. We talked a little bit earlier about your market share gains. Let me use a different reference. Rough calculation at the peak of the US 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?

You know, Jeff, we don't focus or zero in so much on market share as we do profitability. As you know, pricing and market share, are kind of two factors. Last time I checked we don't really get paid on market share. We all -- our shareholders judge us on profitability and return to shareholders. So we watch market share very carefully, but, we may be 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.

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?

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

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

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

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.

I believe the number is$10.5 million, is the kind of Delta in depreciation, off the top of my head..

Okay. So the $10.5 doesn't include the $3.8 million loss.

Yeah, that's correct.

Oh, okay. Alright. And the other income was -- it took a big jump up. What's behind that?

Other income?

Yes.

Other income above the line or below the line? I think that's just disposal of assets, I think. Other income above the line. Oh, I know what you're talking about. That's recovery on bad debts. I'm sorry. I'm in the wrong place.

Geoff, did you catch that?

He left the queue.

Okay.

I'm sorry, that's recovery on bad debt.

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.

Thank you. We'd like to thank all of our investors and analysts for their participation in this call. Thank you and look forward to our next one at the end of our first quarter. Thank you, everybody.

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