Patterson-UTI Energy Inc (PTEN) 2010 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q1 2010 Patterson-UTI Energy Inc. earnings conference call. My name is Keanna and I will be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Geoff Lloyd. You may proceed.

Thank you very much. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss results of the first quarter ended March 31, 2010. 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 the 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 also available through the Company's website or 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, patenergy.com and in the Company's press release issued prior to this conference call.

Now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Geoff. Good morning, and welcome to Patterson-UTI's conference call for the first quarter of 2010. I trust that by now all of you have had an opportunity to read our earnings release, which was issued today.

Our plan is to take a few minutes to review the results for the three-month period ending March 31, 2010. We will begin by briefly mentioning a few of the financial highlights of the just-completed quarter. I will then turn the call over to Doug Wall, Patterson-UTI's President and CEO, who will make some detailed comments on the results of the operating units. After Doug's comments on the quarter, I will share a few brief thoughts on the market outlook. As always, we will be pleased to take your questions following these prepared remarks.

We are pleased to report this morning that the Company recorded net income of $4.2 million or $0.03 per share for the three-month period ended March 31, 2010, compared to net income of $16.2 million or $0.11 per share for the three months ended March 31, 2009.

Revenues for the quarter were $272 million compared to $268 million in the same quarter last year. On a sequential basis, revenues in the first quarter improved by $58 million from Q4, or 27%. We were very pleased with the sequential revenue growth, with drilling recording an improvement of 32% and pressure pumping recording revenue growth of 12%.

EBITDA for the quarter improved to $84 million, which represented a $25 million improvement over the preceding quarter. This better-than-expected 43% sequential improvement in EBITDA was led by a significant uptick in our active rig count and continued strength in our pressure pumping operations in the Northeast.

Capital expenditures for the quarter were $109 million. Once again, most of this relates to our new build program, both in drilling and pressure pumping. I'm pleased to say that even with this level of capital expenditures, we ended the quarter with $64 million in cash and no debt. As previously discussed, we received the proceeds from the sale of our Drilling and Completions Fluids business in January 2010. In addition, we recently filed our federal tax return for a refund of $114 million.

We are encouraged by the recent improvement in activity levels in both of our core business segments, drilling and pressure pumping. We are particularly encouraged by the demand for our new rigs, as evidenced by the new long-term contracts, which we signed during the quarter. This strength in demand, along with our long-standing program of upgrading our rig fleet, caused us to expand our new build program from 15 rigs to 24 rigs, to be activated during 2010.

I would now like to turn the call over to Doug, who will further discuss our operations for the quarter.

Thanks, Mark. First off, let me apologize for the quality of my voice this morning; having a few problems with Houston allergies.

Let me start with some comments on the Drilling Company. For the quarter ended March 31, 2010, the Company had an average of 142 rigs operating, including 132 in the US and 12 in Canada. As Mark said, this is a 39-rig increase or 38% over the average activity level we experienced in the fourth quarter. The Canadian increase was largely anticipated, as typically Q1 represents the strongest drilling season of the year. The US improvement of 35 rigs, or 37%, from the fourth quarter, was stronger than we anticipated. And generally, the activity improvement was across the board.

The biggest activity increases came from the Permian, where we were up 10 rigs; South Texas, which includes the Eagle Ford, where we were up 7; and Haynesville, where we were up 5. Modest pricing improvements occurred in virtually every region throughout the quarter. Average revenues per operating day during the first quarter where $16,440, compared to $16,770 in the fourth quarter.

As outlined in our press release, day rates on rigs working in the spot market did increase during the quarter. However, they generally remained below the day rates on rigs working under term contracts. The substantial increase in the number of rigs operating in the spot market has the impact of lowering our overall average revenue per day.

Average direct cost per operating day were $10,480 for the quarter compared to $10,870 last quarter. This decrease in our cost per day includes the benefit of spreading our fixed costs over more operating days, as well as the increase in lower cost per day rigs.

The activity improvement has continued to date in Q2, with a focus in the oily and the high liquids areas. In Canada, breakup hit us relatively early this year. Most of the rigs were down by mid-March. And we anticipate activity will remain at very low levels until late in the quarter. We're currently running a total of 154 rigs; 153 in the US and 1 rig in Canada.

During the first quarter, we had an average of 39 rigs working under term contracts. Based on contracts currently in place, we expect to have an average of 51 rigs working under term contracts over the last three quarters of the year. Needless to say, we're very pleased with this increase.

So let me give you a little color on our 2010 new build program and expand on the Capex numbers Mark mentioned earlier.

Capital expenditures in our drilling business amounted to $92 million in the first quarter, most of which relates to our new build program. In total, we delivered three new rigs to the marketplace in Q1, an APEX 1500 to the Barnett, and two APEX 1000's, one of which was deployed in the Marcellus and the other one in the Barnett. The APEX 1000 rig in the Barnett represents the first deployment of one of these rigs outside of the Marcellus. And we are very excited to showcase its capabilities in a different market.

Overall, we have been extremely pleased with the startup and the performance of our new APEX rigs. Of our three different models of these APEX rigs, all have been very well accepted in the marketplace, and we believe we will continue to see new opportunities for this technology develop.

Last quarter, we told you we had committed to build 15 new rigs in 2010, including the 9 that we had previously deferred. Our 2010 new build program is now well underway, and I'm pleased to report that we have seen additional demand for our new high-technology rigs. We now expect to complete 24 new rigs this year and we have executed term contracts for 21 of the 24. The majority of these contracts are for three-year terms and are at rates that meet or exceed our hurdle rates for new investments.

Discussions are currently underway with a number of customers on their various equipment needs for 2011 and beyond. We are seeing a lot of ongoing interest in our APEX rig technology, particularly in markets such as the Marcellus, where we feel we have a market-leading position.

We do expect to see some slowing in the uptick of rigs, given the low natural gas price currently. Although we have somewhat limited visibility for the rest of the second quarter, we expect the decline in Canada due to breakup should be offset by increases in the US. For the second quarter, we now expect our rig count to average approximately 155 rigs. We expect daily drilling margins in the second quarter to increase slightly to approximately $6,000 per day, with small increases in both average revenues and expenses per operating day.

Turning now to our pressure pumping business, we had another very solid quarter from Universal Well Service. As Mark mentioned earlier, our revenues for the quarter were up 12% sequentially. Revenues for the quarter were $53.8 million, and average revenue per job increased to $33,680, which I might point out is another new quarterly record for Universal. Although the number of jobs declined sequentially by 5%, the mix shift towards higher service-intensive jobs -- and I'm referring to multi-stage horizontal fracs and nitrogen shale fracs -- this shift continues.

Our average revenue per job in the frac business has almost tripled from a year ago, dramatically showing the change in mix of the jobs we are performing. As activity levels continue to ramp up in this region, we have been able to achieve higher utilization of our quintuplex frac crews, and we're very pleased with this.

On a sequential basis, we completed 50% more Marcellus horizontal fracs during the quarter, and revenue per job is up almost 34%. Although the number of foam and nitrogen jobs was down slightly during the quarter, we expect this segment of our business to remain strong.

Drilling activity and completions in the Marcellus Shale continues to increase, as a number of new projects get underway. We expect this to translate into further improved demand for our services in this market. We spent $9.4 million on new capital equipment for this market during the first quarter, with the majority of this directed towards upgrading our frac capabilities. Our third complete quintuplex frac spread will be delivered in Q3 and we'll begin to generate revenue later this year. Training of the additional crews necessary to support this equipment is already underway to ensure that we maintain our high service quality.

Obviously, we are very encouraged by the ramp-up in industry activity in the Appalachians, particularly the Marcellus Shale. 2010 and beyond will likely see the rapid expansion in this market and we are trying to stay ahead of the growth curve. We are very encouraged by the prospects for both Universal as well as our Drilling Company, where we expect to have 20 rigs operating in this market by the end of Q2, and approximately 25 rigs in the market by the end of the year.

Turning now to our brief comments on the E&P business, where we saw revenues improve by 19% sequentially. Production volumes were up 10% in crude oil and 13% in natural gas. Pricing was better in both commodities for the quarter. To put things in perspective, our net prices, as compared to the same quarter a year ago, were up 93% in crude oil and 67% in natural gas -- more than offsetting the slight decreases we have seen in production volumes.

One final comment before I turn the call back to Mark. With respect to Capex for the entire Company in 2010, our current expectation is for approximately $600 million in spending, including the construction of the new additional rigs that we've announced today.

With that, I'll now turn the call back to Mark for some concluding remarks.

Thanks, Doug. We are very pleased with the progress we've made in the first quarter on a number of fronts. Our average rig count, US and Canada, improved by 39 rigs in the first quarter and 69 rigs during the past two quarters. Once again, we are pleased with how quickly our drilling operations management has been able to respond to the changing marketplace, and activate rigs to meet customer demand.

We are also extremely pleased with the market demand for our new technology rigs, borne out by the new contracts we signed during the quarter. We are also pleased that a number of rigs went back to work in a wide variety of markets, including West Texas and South Texas. Of interest, some of these rigs are of the type that pundits said would never work again. Once again, this bears out our long-standing conviction that it takes a variety of rigs to satisfy the needs of the overall marketplace.

We are also pleased with the improving utilization of our pressure pumping assets in the Appalachians and feel we are in great shape in this market going forward. And, perhaps the most pleasing element of this quarter, is that we return to profitability.

With respect to the balance of 2010, we are seeing cautious optimism from our customers. We use the term cautious optimism to account for the mix of factors that each of our customers is weighing slightly differently.

Number one, optimism about their shale prospects. Number two, optimism with respect to oily plays and liquid-rich plays. Number three, optimism about the overall recovery of the US economy in general, but tempered by number four, concerns respecting the supply of natural gas and the price of the commodity. Against this backdrop, we are pleased to be able to respond to our customers' future needs for drilling rigs of all types and in many, many markets.

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 June 30, 2010 to holders of record as of June 15, 2010.

Before we open the call to questions, we would like once again to thank all of our employees throughout the US and Canada for their efforts each and every day, and working safely and efficiently and often under very difficult conditions. Far too often, we talk about the equipment and the tools, and fail to recognize the importance of our people. We are proud of our team of people and believe they are second to none in their industry. The results they deliver are a testament to their hard work and professionalism. Thank you to all.

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

(Operator Instructions). Kurt Hallead, RBC Capital Markets.

So, I just want to try to parse some of your statements, get a little bit more color. So on the one hand, you feel pretty good about how things are progressing in the second quarter, to give us a general sense of what your rig activity is going to be and what your rig count is going to be.

On the other hand, you reference something about kind of low visibility. So, let's put our best guess hats on here and -- do you think that the increased drilling for oil in liquid-rich plays are going to offset any drop we see in natural gas drilling for the rest of the year? And if so, by what magnitude?

You know, Kurt, historically, we've really talked about the quarter we're in and haven't tried to sort of prognosticate what's going to happen for the next three or four quarters, because quite frankly, our visibility is so poor in the long-term.

The thing that's been good during this last quarter is the significant number of long-term contracts, which our customers have been willing to enter into. And those contracts seem to me to reflect the fact that they're pretty bullish about needing a substantial number of rigs over the next couple of years.

That's, to me, the greatest sort of sign of the positive direction of the industry is what I see as the continued demand for rigs, and the fact that our rig count has remained strong and continued the upward trend during the second quarter.

Against that, though, we're aware of the price of natural gas. We're aware of the concerns people speak about, about supply of natural gas. And so it's real hard to try to say -- in the aggregate, does the oil plays, does the liquids-rich plays, drilling to maintain leaseholds, et cetera, et cetera, et cetera, all counterbalance supply -- is supply correctly understood? We don't know.

Do you think that Patterson is uniquely or better positioned to benefit from a shift to more oil drilling?

I think we've -- by virtue of the size of our fleet and the capability we've always had in some of the oily areas, I think we're very, very well-positioned to do so. Whether we're better or worse positioned would be a comment about other competitors that I just wouldn't want to go to. I think we're very well-positioned. I think we've always been positioned to take advantage of a number of basins and so to the extent to which we see expansions in these other basins. That's why in my remarks I particularly called out South Texas and West Texas, in particular. But I don't want to speak to what others can do.

If I heard you correctly, you said $600 million in Capex for this year?

Yes, sir.

So I think that speaks to what you think's going to happen from a rig activity standpoint, no?

Well, you know, we don't build rigs for this year. We build rigs for the long-term. So, we feel that we've got the balance sheet that supports this. The new rigs have been very, very well-accepted by our customers. Numbers of them are willing to sign term contracts; all of which -- plus our strong balance sheet, sort of supports us in going forward with this kind of a program.

Okay. And have you started to see any impact whatsoever on day rates or on your operations specifically as it relates to this concern over natural gas?

You know, Kurt, we've heard a lot of talk and a lot of people in the industry have been talking about it. To date, we have not seen any real indications of it. In fact, we're seeing continued strength on the crude oil side. And I think the number of term contracts we've signed in the last quarter suggests that there is some strength in some other areas as well.

Let me just rap on this -- so you're very bullish on the Marcellus play. That came across quite clearly. Can you give us an update on what factors are relating to potential regulations and environmental issues as it relates to hydraulic frac and other things that the government is looking into? And whether or not you think it's going to be a federally regulated environment or is it going to be state regulated? Can you give us some color on that?

You know, Kurt, we're aware that, obviously, that there's some pressure in Congress towards putting the natural gas and oil industry under the Clean Water Act. That's obviously one of the things that is a potential. Trying to estimate the likelihood of any bill being passed by the Congress strikes me as one of the great hazards that one could undertake, because I don't see how you can predict, at this point, what direction the legislative path will take.

I can tell you that we see that there is a possibility of some kind of federal regulation. We have been subject to a substantial amount of state regulation. And I guess I feel as if, as long as the regulation affects everybody equally, then we're prepared to deal with it in an appropriate faction. And quite frankly, I expect it to be that kind of legislation -- it will affect everybody equally. And we'll deal with it.

Okay, great. Thank you so much.

Scott Gruber, Bernstein.

I wanted to turn to the pressure pumping segment, another big step up in rates for the Marcellus activity in 1Q. Where do rates stand currently for the Marcellus jobs versus the 1Q average?

You're asking about rates for the jobs?

Yes, maybe you can give us a percent increase versus the first quarter.

Well, we really don't normally get into talking about rates on jobs. And I think if you look at the average revenues per job, you can probably get a pretty good feel from that. There's still -- there's roughly we think 20 horizontal frac crews in that market. Utilization has improved in the last quarter. Typically, in that business, when utilization improves, pricing goes up as well.

So I think, certainly, the quality of jobs is incredibly important in that market. We are seeing some improved pricing, but I'm not really prepared today to talk about rates. It probably wouldn't be meaningful in any way, shape or form that I could give it to you. But I would look at just comparisons of average revenues per job should help get you there.

Okay. And how much is revenue per job up versus the first quarter? Do you have an idea on that front?

I have -- I think it was -- on the horizontals, I think it's up 34%. But keep in mind, part of that is the -- those multi-stages, the more of them that there are, that average revenue is going to go up. So there is a mix issue involved in there. But certainly what (multiple speakers) --

Was that 34%, though, the 1Q versus 4Q increase?

Yes, I think that's the number that I had it earlier in my comments.

Have you seen another -- given that rather rapid improvement, I would assume that the current average is well up versus the first quarter average. Is that fair?

I think we continue to see modest improvements. The pricing is all about utilization of the equipment. And when the equipment gets utilized and people have to wait for a frac crew, certainly price goes up.

The increase in average revenue per job that's been talked about here is driven by -- primarily by mix. Historically, we've done a lot of smaller cementing jobs and fracking jobs in the Appalachian area. As we do more and more of these horizontal fracs, those jobs are many multiples larger than, say, a cementing job on traditional work. And that's producing these large increases in revenue per job in our pressure pumping business.

Now I would also assume that you're seeing increased maintenance expense on these units, as a lot of your competitors have talked about, across the different plays, just given the strain being placed on the equipment due to the intensity of the jobs?

That's correct. I think any time you run the equipment at the pressures and for the length of time that we are, certainly, your maintenance costs go up on your pumps and all your expendable equipment.

I would assume that, given the increase in the maintenance expense, that you'd offset that with some pricing improvement?

Sure hope to (multiple speakers) --

(multiple speakers) -- be neutral on a cash flow basis. Did you think there's room to continue to push pricing up higher, just given the increased maintenance expense?

Well, I believe so in all markets. When you think about the fracking business in general, I think what people are finding out about these multistage horizontal fracs is it is much harder on the equipment. And I think you're going to have to see costs go up in every one of those markets just because we're wearing out the equipment much faster.

Okay. One last question. Given the wide oil gas spread today in your clean balance sheet, would well servicing assets be of interest to diversify your services and increase your crude exposure?

I think we've always had a policy of saying that in respect of opportunities for acquisitions, we look at a lot of things. But for us, a key component is do we think that it's going to make the business significantly better for our existing shareholders? That's a test that we've applied consistently for more than 15 years.

We're not going to speak to any specific acquisition in advance, obviously, but the basic theory has been that unless it's going to significantly improve the lot of our existing shareholders, we're not inclined to do it. So that's the standard of analysis that we've used historically.

Quite frankly, during this last period of time, the expectations on the part of sellers have been for prices that have made it not very attractive to us to be acquirers. And so we've been devoting our capital to improving our business internally.

Okay, thanks.

[Christopher Butch], Raymond James.

Congrats on the good quarter. My first question is related to some recent commentary from the IPAA. We heard that they may increase the rig count by 200 to 300 rigs in some of the shale plays by year-end. And I'm wondering, as you look at the current fleet, do we have that sort of available capacity on the high end? Would we have to dip into lower spec rigs and move into the renewable market? I just want to get your general thoughts on that.

Well, I think, Chris, that's actually a question that's probably better directed at the customers. I think there are plenty of rigs available today in the drilling industry that can adequately do that business. For example, we probably have 60 rigs available today. Now, some of them may be mechanical, but we still have some CSR electric rigs available. They're more than suited to kind drill that work. But we have seen this move -- there's no question, we've seen this move throughout the industry for people looking for very -- fit for purpose-specific rigs.

So I don't know that we can answer that. All I can really say is that we're prepared to do both. We offer them existing equipment, which we think can adequately do the job. If they're not interested in that, we're prepared to build them a new build, if the terms and the rates and the return that we get over it, over the lifetime of the rig, are adequate to us.

Okay, fair enough. Unrelated follow-up -- you all recently, if I'm not mistaken, had another frac spread delivered up into the Marcellus. And I was wondering, relative to your existing equipment there, what are the margins, the revenue and the utilization look like for that newer frac spread for that new equipment?

Well, that new frac spread really came to us late last year and we don't give specific returns, I guess, on specific equipment. Suffice it to say, I said earlier that the utilization of that frac spread has gone up substantially. We're far from full utilization, but we're very pleased with the utilization. And we think as we go forward, we will see continued utilization.

And once again, just like the drilling business, we don't invest in that equipment unless we feel it meets our minimum hurdle rates. And in this case, we're very pleased with what we've seen so far.

Okay. And final question. Last quarter, someone had asked you if you believed $220 million in 2010 pressure pumping revenues was a possibility. You know, obviously, it's a possibility. You said it would depend on what demand turned out to be. One quarter into it, do you have any color you'd like to add? Or same story?

Well, John, do you want to --?

We tend not to comment on full-year numbers simply because our visibility is not that good. But as we look towards second quarter, we think versus first quarter, a revenue increase of 10% overall seems reasonable to us for that time period.

Okay, well, thank you. I'll turn it back.

Dan Boyd, Goldman Sachs.

Just wanted to make sure I understand how to think about margins going forward. Assuming spot market pricing, which is rising, but assuming it stays the same, and activity pretty much stays the same going forward, should we expect -- what should we expect for margins going forward? Is there going to be some pressure as things roll off contract? Are we completely past that now and we could see rising spot pricing potentially just flowing straight to margin?

You know, Dan, I think the way we look at it is that from our perspective, and we have pretty limited visibility, we are expecting a modest improvement in second quarter over first quarter. That's really how we're seeing it right now.

Beyond second quarter, trying to sort of think about pricing in the industry and margins is pretty difficult for us, given the context we started out with in the call about not knowing where the rig count is going deep into the future because of this mix of factors between liquids and oily rich plays; on the other hand, concerns about the gas business, but vice versa, there's the strength of the long-term contracts.

So it's a big mix trying to sort of see that. And it's real difficult against that backdrop of not knowing what the utilization is going to be, to try to really sort of look at margin anywhere beyond the next quarter.

Yes, I guess I'm trying to look at it to just better understand the roll-off effect of contracts. And I think we're past the negative headwind of things rolling off contract. I'm just not 100%. So, assuming utilization stays where it is, that everything that's contracted kind of rolls to the spot market -- any color?

Yes, I think -- in our case, I think it's going a different direction. We're actually increasing the number of rigs during the year that are under term contract. So if everything else stayed the same, that would produce higher margins per day as the year progresses.

Okay. That's what I thought. So we are past the trough in margins, assuming --

There's two parts to that. You've got to kind of break it apart. You have your spot rate rigs and the pricing that occurs there occurs there. The thing we have greater visibility of is obviously our term contracts. You have some number rolling off, some number coming on. In our case, there's more coming on term than going off. And those are at margins well higher than the average. So again, everything else kept constant, the term contracts rolling on and off would produce a higher margin per day as the year progresses.

Got you. That's very helpful. And then on your expectation for activity for 2Q, is there any underlying industry trend in the rig counts that's behind that? Does that assume the rig count continues to go higher from here? Or does that assume the overall rig count flattens out?

It's hard for us to think in terms of the overall rig count. We leave that to you and other analysts. We have pretty good visibility -- about 90 days out -- about our rig count traditionally, and have been reasonably close when we make comments. And that's what the comments here today were based upon, what's coming out on new term contracts and our visibility of the spot market.

Okay. Thanks. I'll turn it back.

Geoff Kieburtz, Weeden.

Let me kind of pick up on that last line of inquiry, I guess. Doug, do you have any rigs, mechanical rigs, drilling horizontals in shales today?

Yes.

Okay. Are they seeing rising rates as well?

Yes, I think they're -- they certainly are. I think they're getting pulled up. The really good quality mechanical rigs that can adequately do the shale-type work kind of draft in at some level in behind the real high technology rigs.

Geoff Kieburtz Okay, but there's a price differential but they're seeing the same trend lines?

That's correct.

Okay. And John, I think from your prior comment, we can conclude that the new contracts that are being signed for term work are at higher rates than the current spot right, correct?

Yes, Correct.

Okay. All right. I guess -- I'm not sure who to direct this to, but I'm a little bit surprised that you can increase the number of rigs you're delivering this year by 9 on such short notice. Can you -- I mean, do you have that ability? I mean, it seems like your supply chain is pretty short here, is that right?

Geoff, I think that this underestimates Patterson's ability to construct rigs economically and efficiently. One of the things that we've spoken about in the past is that by virtue of the scope and scale of our Company, we have facilities and capabilities of putting rigs together and building rigs substantially greater than we think has been commonly recognized. And a real area of expertise for us and a foundation of our Company is that -- plus our balance sheet, plus the ability to, in effect, be able to acquire the equipment necessary effectively, all kind of come together, plus the long-term contracts that inspire us to want to do it, to be able to produce additional new rigs and to do so relatively quickly.

Okay. And, I mean, you have to have the components, so I understand your capability, internal capabilities to assemble the components, but were the components making up these additional 9 rigs already in-house?

No, not necessarily. It's a combination of things, Geoff. We had some components in-house. We've bought a significant amount of stuff during this first quarter, and we're now able to go forward and we think make this delivery of 24 rigs during this quarter. Remember that part of it were the carryover rigs that we had delayed taking delivery of. So some of the equipment was already there; plus we were able to quickly expand our supply chains.

Do you see any evidence that that supply chain is starting to tighten yet?

Yes.

Okay. So we can't necessarily rely on having a six to nine-month lead-time on new equipment for any length of time into the future?

I don't want to go into the backlog of our suppliers and try to estimate how long their supply chains are. We think we can make the delivery schedule of our 24 rigs that we're talking about this year. That's really as far as we really think we need to go today.

Sure, okay. And then on the frac jobs in the Marcellus, I think, Doug, you mentioned that your -- the spreads are increasing their utilization but they're not at fully utilized state yet. I guess, two questions -- do customers have to wait? Or can you respond pretty immediately to an incoming request today? And how long do you think that's going to persist? How long is it going to be until you have to tell people they have to wait?

Well, I think we are having to tell people they're having to wait today. In our case, we just really have the two [quit] frac spreads at this point. We've worked with a number of customers up there -- people, as always, in this business get their name on the board and estimated timing. We're not always there on the exact date but I think for the most part -- but there's no question we've also had to turn some work away.

Okay.

Geoff, on the other hand, we do have a third [quit] frac spread being delivered this year that's been ordered. And we're getting that crewed up and the crew is getting ready for it. So we expect that to be in place and helping us in the succeeding quarters.

And what is the lead-time on a frac spread for you at this point?

It's very similar to a drilling rig. It's probably nine months to potentially up to a year.

Okay. Great. Thank you very much.

John Daniel, Simmons.

Good morning, guys. Good quarter. Hey, you mentioned 20 horizontal frac crews in the Marcellus. Given where drilling activity is headed, how many crews do you think are needed in the region?

Ultimately, I think there will be even more than that, but I -- today, I couldn't really tell you or give you an idea of what the utilization of everybody else's equipment is. I do know that when people have come to us and we've had to say, gee, I can't get there till such and such that the other people have been able to find another frac crew. But I would point out there's a -- we think there's a pretty vast difference in service quality in that marketplace, and which should be worth the premium to us. And it's one of the reasons why we want to expand our capabilities there.

Understand. And you mentioned you can't get to something until such and such. Can you tell us what such and such is? Is it end of the summer now?

It's likely the end of the summer.

End of summer, okay. I don't mean to beat a dead horse on the cash margins, but the rigs that are rolling off the term contract now -- don't those rigs carry a higher cash margin than the rigs that are presently being signed up for term contracts? Or am I mistaken on that?

Yes, I think you're mistaken. These are from various years.

They're probably about the same.

Okay.

But I should point out, we have very few rigs rolling off term contracts. So don't overestimate that. As John said earlier, we have far more rigs coming on to term contracts than really rolling off.

Okay. And then just last one for me is, you noted the increase in drilling activity in the Permian. Would you be willing to speculate how many more rigs are likely to be added out there? And if that happens, which I would think would happen, wouldn't you expect to see cash margins actually trend lower, given what the pricing environment is in the Permian?

Well, I certainly wouldn't speculate on the number of rigs that could go to work out there. It's almost limitless if the price of oil keeps going up. Currently, we have 40-some rigs working in that marketplace. We have another 30 or so we could put to work. But I couldn't -- I really wouldn't want to speculate on how many more rigs. Again, that's a question -- I just don't know how many more operator -- I think virtually everything that people want to drill is being drilled when you've got $80 oil.

Right, okay. Just one quick final one for me. It's -- if you go back historically and look at the shales, like the Barnett, it was sort of an 800,000 horsepower rig to efficiently drill the well. And then as you get in the Haynesville, you see the shift of 1500 horsepower rigs. Do you see the possibility that drilling requirements might get to the point where they're requiring 2000 horsepower rigs as the preferred rig over 1500 horsepower?

Well, I suppose that's possible, but I think today, a 1500 horsepower is plenty enough horsepower for -- the Haynesville is probably the most demanding application that we're in today. But if you tell me five years from now that we were drilling 12,000-foot laterals, yes, I guess potentially that could be a situation where we'd have to have higher horsepower rigs. But I don't see that happening in the foreseeable future.

Fair enough. Okay, that's it for me. Thanks, guys.

Arun Jayaram, Credit Suisse.

First question -- John, it looks like you guys have changed the reporting structure in pressure pumping, now reporting less SG&A and higher direct operating costs. Just trying to understand sequentially what the change was in margins, given that reclass?

Yes, to your point, yes, we have. We're kind of reevaluating and trying to get the drilling and pressure pumping business classifying SG&A the same way, so it's the same across all the units.

In connection with that, we report dollars in the pressure pumping operating costs that a year ago, would have been in SG&A and reflected it in both years. And for anybody who would like the breakdown by quarter, how it impacts 2009, you just send me an email and I'll send it back to you. Or if you don't have my email address, please send it to investrelations@patenergy.com and I can provide you that.

Arun, I think you can easily back into the impact [appeared] in the last year for the first quarter, which for 2009 first quarter, it was $3.4 million roughly.

Yes, I was more interested maybe in the sequential change from Q4 versus I think the margin you did was, like, 9160 per job?

Yes, I do not have it broken down that way here in front of me by job.

Okay. That's fair enough. I could ask that offline. I wanted to get a little bit more detail on the timing of the new builds for the balance of the year. I think you have what, 21 more through '10?

Arun, this is Doug. We expect to have 9 -- or, I'm sorry, 7 rigs out in Q2. And I think you can probably equally say that there would be plus or minus 7 in the last two quarters. But the one we have the most visibility at this moment is Q2. And we do expect to have 7 new rigs out in Q2, which would get us to the 10. And I think if we can get to that run rate, there's no reason why I think we can't get 7 and 7.

Okay, sounds good. And my last question, Mark, in your prepared remarks, you talked about capitalizing on other opportunities. Can you comment on what kinds of things you're looking at and -- et cetera?

Yes, you know, it's interesting, the way we wrote that remark just to say that we always try to look at a wide variety of opportunities in the industry, both in our core businesses of drilling and pressure pumping; but we've also been willing to look at other things as well.

Quite frankly, I don't think that there's a huge interest in stepping out of our core businesses at this point, so I don't think that's anything that we were trying to signal is more likely. Frankly, we just wanted people to realize or know that we do take seriously opportunities elsewhere. (multiple speakers) But, you know --

Right. I was just thinking (multiple speakers) --

There was no meaningful change in direction that we were trying to signal by the way the words were cast. So, we were really trying to just say that we always look at opportunities; we've always applied the same kind of analytics.

Yes, I was just wondering if, perhaps -- I don't think you've done an acquisition maybe since the Tom Brown deal, but if there's been a change, perhaps, in the bid, as spread and acquisitions or anything like that.

You know, frankly, I think that we've built a lot of value for shareholders by acquiring rigs over a period of time. We obviously have one of the largest fleets of rigs, so we've got that covered, we think, at this point.

We've invested now significantly in new build rigs because we think that's what the market is looking for, at least in a part of the market. We want to be sure that we have the assets to cover it. At the same time, we've invested heavily in our pressure pumping business by adding the quintuplex pumps, so that we're -- a quintuplex pump fracking units, so that we're in a position to meet that demand as well, and take advantage of the strategic positioning that Universal Well Services has historically enjoyed.

So what we've basically done, as I see it, is taking the money that we were spending on acquisitions and directing it towards internal growth over the last several years. And quite frankly, what I'm really pleased with is that we've been able to do that, continue to pay a dividend, and have returned a lot of money to shareholders in years past and still have cash on our balance sheet. That to me is a huge accomplishment.

Right. And I guess from your comments, Mark, the internal opportunities still, in your mind, still provide the best returns -- objectives versus acquisitions, et cetera? Is that fair?

That's correct. But we also want to make people know that we continue to look at opportunities. And that's been the place where we've seen it so far to date. But we continue to be open-minded. And that's really what I think I was trying to say.

All right. Thanks a lot, guys.

Alan Laws, BMO Capital Markets.

You're still encouraged about the near-term; I like that. You have a strong demand for the new rigs. Are there still opportunities to mobilize any rigs that are currently stacked? Or is this strictly a new build game now?

No, I think we've still been mobilizing rigs that are currently stacked from some markets to other markets that are hotter. I think there's a real mix in opportunities facing us. I mean, obviously, there's not a lot of new capital that's going into, say, certain markets like West Texas, but we're still mobilizing rigs there. We're still taking -- other than new builds, we're still mobilizing equipment from various markets up into the Marcellus. So I think it's a wide range of opportunities that we're still seeing, Alan.

Well, you know, Alan, you just see that the rig count having gone up by, for us, over the last two months, of 69 rigs. And you think about subtracting from that the number of new build rigs and you get a very large number of the fleet that is not new rigs that have gone to work. We gave you the number this morning of 153 rigs in the US -- 154, which is obviously up from the last number that we reported of 138 and 8 in Canada we reported for March. So you can see that we continue to add rigs and that's beyond just the new builds that we've announced.

I concur. My second one is (multiple speakers) --

I didn't mean to be -- get argumentative, I was just --

My second question, though, it relates sort of to that. The top drive sales seem to have been pretty strong here from some of the equipment guys. You upgraded your existing fleet quite a bit. Can you remind us of your plans on the top drive investment this year, and maybe what that does to the marketability of older rigs in the current market?

You bet. We're adding approximately 41 top drives this year to various rigs. We've been doing that really the last couple of years. At some point, I think that slows down; but again, for 2010, I believe we'll -- we've certainly got 40 plus on order, which includes all the new rigs as well. So, we've made a pretty major investment. Each one of those top drives, as you know, is roughly $2 million installed. So it's a big number, but it's something that we've certainly, as a piece of equipment, that a lot of our customers today, particularly if they're drilling horizontals, demand that piece of equipment.

So would you say most of your active fleet then today must -- or will have top drives by the end of the year; is that fair?

Not exactly. Probably two-thirds, somewhere in that order of magnitude.

If you looked at it today, even if you took the 40 that we're adding this year, you still -- we'll still have a significant number of rigs that do not have top drives.

Okay. My last question is on -- you mentioned the favorable oil economics. Any thoughts on how high the oil rig count could go in this environment here in the US? Putting you on the spot.

Well, I'd hesitate to speculate. I don't know. We just see continued opportunities in places like the Bakken and the whole Williston area. Obviously, there's some -- the Texas Panhandle has some oil-rich and liquids-rich plays. The Eagle Ford looks very promising. And of course, West Texas, I think still has opportunities. So, I don't remember exactly what the peak was at the last cycle, but (multiple speakers) --

(multiple speakers) over 700 -- I think it's just over 700.

Yes. But quite honestly, any drilling rig out there is capable virtually of drilling for both. So if the total market is 2400 or 2500 rigs, I guess that might be the limiting number.

All right. That's all I've got. Thank you very much.

Jud Bailey, Jefferies & Company.

Actually, Jud Bailey. Good morning. Two or three quick questions. I believe you mentioned in your prepared comments you were putting your first APEX 1000 in the Barnett, that's the first one that's gone outside the Marcellus. It may be a little early, but can you comment as to what kind of appetite you may have for that kind of rig outside the Marcellus? Maybe more in the Barnett or even in some other basins?

Well, it probably is too early, Jud. We've -- the rig's been up and running for less than a couple of months. I think time will tell, but it's highly suited, we think, for both the Barnett and we think there's a lot of applications in the Eagle Ford for that rig. It's probably a little too light of a rig for the Haynesville, but certainly, the Barnett and some sections of what we see the Eagle Ford, we think it would be ideally suited. It's a very fast-moving rig. Lots of features on it that we think there's a niche application for.

Okay, that's great. And then have you given details of the 21 rigs you have under -- new builds you have under contract, how many of those will be going to the Marcellus?

We have not, but I -- and I'm not going to give you exact numbers here, just for competitive reasons. Approximately half of the new builds are heading to the Marcellus. A significant number are going to the Eagle Ford.

Okay, and great. And my last question was, you've got 24 new builds delivering this year. Are you having discussions for rigs perhaps to be delivered in 2011 or start contracts then?

Well, we're certainly having conversations with customers. We have nothing really at this point we'd like to divulge. We haven't [been that in] budget. We certainly aren't ready to discuss or announce any new contracts, but -- so I think my answer is no. We do see continued demand. At this point, we really don't have anything planned.

Okay, great. I'll turn it back. Thank you.

John Tasdemir, Canaccord.

Thanks for squeezing me in, guys, and we don't have much time so I guess my simple question was, I think I heard you say, Doug, that you had some mechanical rigs drilling horizontally in some shales. And I guess my question is, where and why? In the sense of -- are there just some of those rigs that are -- is that really all you need in those areas? Or is it the fact that there's not the new build or the new purpose rigs that are available for those markets?

No, John, that's kind of an interesting question and I'll go back to something -- I'll try to answer your question in a couple of different pieces. One, I know we have them working in the Barnett today. I know we have them working in Haynesville. And I believe there's a couple -- well, there's certainly some mechanical rigs working up in the Bakken.

And quite honestly, the reason for it is that they can do an adequate job. And in fact, one of our customers who has a number of our rigs working in one of those plays, his best-performing rig is a mechanical rig of ours that does not have a top drive. And he has never once said to us, you guys have got to go put a top drive on this rig.

So, I guess you'd have to talk to the customers, but there's -- we seem to forget about the people resources in this business. And I think there's a lot of applications, even in these shale plays and in the horizontals, where it's not 100% necessary to have all of the bells and whistles that we sometimes hear about all the time.

I think that's very interesting. I guess the other thing just to kind of follow-up on that -- I know there's probably not tons of them, but those particular rigs like you mentioned in the Bakken, if they're just -- if they are very successful rigs, would you get a premium for that rig over maybe a different type of mechanical? Or is it the spread -- the day rate spread from a new purpose build rig less or narrower on that rig perhaps?

I think it's hard to answer that question. I mean, a lot of people have had some of our rigs working for them for four, or five, six years. They like the rigs. They don't ever want to get rid of them. They do pay you a premium over a spot market rig that they know nothing about.

But I'd also have to say that there's no question that there is a premium between a high-end, high-technology rig and almost any other, whether it's SCR or mechanical; there's going to be a premium. And like I say, we play in all of those markets.

And I think you'd just have to understand with the high-end technology rigs, you've got a lot more capital invested. As I mentioned earlier, those top drives are $2 million. You start talking about AC controls, you're up in that same dollar figure when you'd add in hydraulic catwalks.

You've got to get a return on those things. If the customer is demanding them, he's going to have to pay a higher price. Plus the fact that with all those bells and whistles, the maintenance costs over the long-term are going to be substantially higher.

Okay. Thanks, Doug. I appreciate that.

With no further questions, I would now like to turn the call over to Mr. Mark Siegel for final remarks.

Okay. Before I do so, I'm going to turn it back to John Vollmer.

Yes, just one additional comment I'd like to make. Due to the relationship between US and Canadian tax rates in the first quarter, our tax rate was probably a little bit higher than we would anticipate for the year, at something -- it was first quarter, something a little over 37%. We're anticipating an annual tax rate closer to 36.5%.

Okay. Thanks, John. I would like to thank all the investors and all of the analysts for their participation in this call, and tell everybody we look forward to speaking with them again next quarter. Thank you.

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