Patterson-UTI Energy Inc (PTEN) 2009 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Patterson-UTI Energy second quarter 2009 earnings conference call. I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will be facilitating a question-and-answer towards the end of today's conference. (Operator Instructions). As a reminder, this conference is being recorded for replay purposes. On behalf of Patterson-UTI Energy, I now turn the call over to Mr. Jeff Lloyd. Please proceed, sir.

Thank you, Jennifer. Good morning, and on behalf of Patterson-UTI Energy, I would like to welcome you all to today's conference call to discuss the results of the three and six months ended June 30, 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 is important to note that actual results could differ materially from those discussed in such forward-looking statements, important factors that could cause the 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, regulation and planned capital expenditures, excessive availability land drilling rigs, including as a result of the reactivation or construction of new land drilling rigs, adverse industry conditions, difficulty integrating acquisitions, demand for oil or natural gas, shortages of rig equipment, and the 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 statements.

Now it is my pleasure to turn the call over the Mark Siegel. Mark?

Thanks, Jeff.

Good morning, and welcome to Patterson-UTI's conference call for the second quarter of 2009. I trust by now that all of you have had an opportunity to read our earnings release, which was issued earlier this morning prior to the opening of the markets. Our plan this morning is to take a few minutes to review the results for the three months ended June 30, 2009 and to indicate some of the financial and business highlights from the just-completed quarter. I will then turn the call over to Douglas Wall, Patterson-UTI's President and CEO, who will make some brief comments on the individual business units. After Doug's comments on the quarter, I will make a few 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 for the three-month period of $17.7 million or $0.12 per share, compared to net income of $81.4 million or $0.52 per share for the three months ended June 30, 2008. Revenues for the quarter were $161 million, compared to $526 million for the second quarter of 2008. EBITDA was $42 million for the quarter, and $138 million for the six months. As you've seen in our press release, our earnings this quarter were impacted by, number one, the significant drop off in the number of rigs running in both the U.S. and Canada. Number two, lower pricing in the spot market for rigs. Number three, the slight delay in getting some of the new-built rigs into the market. And number four, the continued decline in the number of traditional jobs in our pressure pumping business in Appalachia, and the downward pressure on pricing in this business.

The entire north American natural gas industry experienced a significant decline, and all of our business units experienced lower utilization rates in pricing during the quarter. The North American rig count is now at levels we have not seen since the early 2000s. We have undertaken numerous cost control steps to align our business with the current level of market activity, while striving to maintain our capability to respond promptly to expected increases in activity. We spent $157 million during the quarter on capital expenditures, primarily directed towards the previously-announced deliveries of new rigs. I'm pleased to say that we ended the quarter with $168 million in cash and no debt.

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

Thanks, Mark.

Let me start with the drilling company this morning. For the quarter ended June 30th, 2009, the company had an average of 63 drilling rigs operating, including 61 rigs in the U.S. and two rigs in Canada. This compares to an average of 127 rigs operating, including 116 in the U.S. and 11 rigs in Canada, for the first quarter. For the second straight quarter, our rig count fell by almost 50%. However, it should be pointed out that the rig count remained fairly constant throughout May and June, and we are now starting to see some improvement.

Average revenues per operating day during the second quarter were $17,780, compared to $19,670 in the first quarter, a drop of approximately 10%. Average direct costs per operating day were $9,960 in the second quarter, compared to just over $11,000 for the first quarter of 2009. Again, a reduction of approximately 10%. There were a number of reasons for this large revenue drop, including more rigs operating on stand-by rates, and construction delays, as Mark mentioned, on some of our new rigs. In the third quarter, we expect average revenue per operating day of approximately $16,500. To the extent we increase our spot market activity levels, this amount could decline further as a result of spot rates today being lower than term contract rates.

We are pleased with the results of our cost-control initiatives over the past six months. We have reduced our head count significantly, and streamlined our operating infrastructure. Although we will continue to fine-tune the organization as the year unfolds, we do believe that we have already reduced the organization so that it is aligned with current market conditions.

During the second quarter, average direct operating costs operating per day benefited from a number of factors. Again, these include the stand-by days, where the rigs aren't operating and don't have significant costs, and secondly, an actuarial adjustment, which reflects improvements in our safety experience. The significant investments we have made over the last couple of years in training and our equipment are beginning to pay large dividends in our worker's compensation costs. Given the low number of operating days, as you know, small changes in expenses can significantly impact per day costs. During the third quarter, we expect direct operating costs per operating day of approximately $11,200.

Let me talk about the market for a few moments. The rig count has picked up modestly in the last month or so, and we expect the next couple of quarters to the remain in a rather narrow band but with a somewhat upward bias. For the third quarter, we expect our average U.S. rig count to be approximately 67 rigs, and the Canadian count to average three. As could be expected with a substantial drop in industry utilization, pricing pressure in the spot market has been very severe. In the second quarter, we averaged 32 rigs working under term contracts, including seven rigs which earning stand by revenues. This is down from 49 rigs working under long-term contracts in Q1. We expect that rigs working under term contracts will average 27 in the third, and 30 in the fourth quarter. In the aggregate, we are benefiting from the impact of our new rig construction program, and all these rigs that are coming into service in 2009. In 2010, we expect to have an average of 28 rigs working under long-term contracts, and in 2011, 20 -- 21 rigs under contract.

Let me make a few further comments on our 2009 new build program. Drilling capital expenditures for the quarter were $148 million; virtually all of this related to our 2009 new build program. During the first quarter we activated four new rigs, we activated three during the second quarter, and already in July we have activated a further four rigs. This total of 11 new rigs include two new APEX 1000 rigs, our newly designed rigs for the Marcellus. Both of these new APEX 1000s were delayed slightly, as we and the manufacturer worked out some initial design and build issues.

Given the new innovative design features of these rigs, some of the challenges we encountered were not entirely surprising. We are extremely pleased with the start-up of these new rigs, given their advance technology features. We have spent a little extra time load testing the rigs in the yard, as well as training our personnel before they get shipped to the field. Our customers are delighted with the rigs, and we have had a great deal of interest in this new technology from numerous other customers.

You also may recall that our first two Walking rigs were employed in the Marcellus earlier in Q1, and to date they have performed extremely well. We are now drilling multiple wells on a single pad, and have helped our customer in this market achieve significant well efficiencies. As you know, Patterson-UTI has a market-leading position with this technology, and we are extremely happy with our position in virtually all of these developing plays.

Turning now to our pressure pumping business, our results for the second quarter were once again hampered by low commodity prices and fierce price competition in this market. Revenue for the quarter was $33.6 million, down 12% sequentially. The number of jobs completed was also down by 12%. Encouragingly, average revenue per job remained flat at just under 20,000 per job. Although we have seen some pricing pressures and they certainly have intensified, we have achieved approximately 30% margins for the first six months, through effective management and cost controls. Capital expenditures during the first quarter were $6.7 million, mostly related to the delivery of additional [point of flex] pumps, and associated equipment necessary to frac the increasing number of horizontal wells being completed in this market.

Speaking of these horizontal wells, we completed five horizontal fracs in the Marcellus during the quarter. On average, these fracs involve six to 10 stages. They were completed in a three to five-day period. In addition, we also performed 18 horizontal stimulations during the quarter in the Huron and the Chattanooga shales, using our nitrogen pumpers. The biggest of these jobs was one where we pumped 52 million standard cubic feet at a rate of over 190,000 standard cubic feet per minute, which we believe to be a new record for the Appalachians. So even though the pace of completions has been slower than expected, we are extremely encouraged by the longer-term prospects in the deeper Marcellus and Huron shale plays.

Low commodity prices have caused some retrenchment in the traditional business in the Appalachians, as well as fostering some delays in these new shale plays. Without a recovery in gas prices, we expect that the traditional business activity will likely remain low, and may moderate the development pace of the shale plays. However, we feel we are very well positioned for the eventual turn in this market.

Turning now to the drilling fluids segment, the dramatic decline in the rig count has obviously hampered our fluids operation as well. Revenues for the quarter were down 27% sequentially. The lack of activity in the Gulf of Mexico, coupled with the dramatic decline in the number of wells being drilled on land, will continue to negatively impact both our revenues and earnings for at least the remainder of 2009. Our E&P business had a small operating gain this quarter; even though average oil prices were up 45% sequentially, our average volumes were produces were down by some 14%. Average gas volumes produced remain relatively flat, and average natural gas prices were down by 2%. Unless we see a dramatic improvement in commodity prices, we do not foresee any meaningful changes that would impact these numbers for the rest of the year.

So before I turn the call back to Mark, let me give you a brief glimpse of some of the things we have done to address the weaker demand for oil services, and our cost structure. We have consolidated facilities and reduced the head count throughout our Company. We continue to chase the supply chain for cost savings. We believe we have sized our organization to meet what we feel are the requirements of the current market. At the same time, we are very determined to maintain our ability to react quickly to the next market upturn. Unfortunately, at this point we just don't know when this might happen.

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

Doug, thank you.

Although we can't say with certainty we've seen the bottom, we do believe that the worst period in the rig count is behind us. During the last few weeks our rig count has steadily increased, and we see some signs from customers that some additional demand for rigs may arise late in 2009. As to our operations, we think the steps which we are taking, and have taken, which Doug outlined, will make our Company leaner and stronger for the long term. In short, we will be very nimble.

Patterson-UTI has a track record in past industry cycles of being able to scale the business to the current level of activity, whether expanding or contracting. We have done this, and we will continue to do so. We are trying to maintain our ability to quickly recover, to run a large number of rigs. The organizational changes, along with our large fleet of new and recently upgraded equipment, makes us confident that we will greatly benefit from the next upturn in drilling, particularly in such areas where we believe the growth will occur, such as the Haynesville and the Marcellus. I'm also pleased to announce today that our Company declared a quarterly cash dividend in its common stock of $0.05 per share, to be on September 30, 2009 to holders of record as of September 15th, 2009.

Before we open the call to questions, we would like to take the opportunity to express our sincere appreciation to all of our employees. Far too often, we talk about equipment and new high technology, as if they were the only key to getting wells drilled and completed and frac jobs accomplished. In all of our business segments, we recognize the importance of hard-working and caring people. We have some of the best in the industry, and we wouldn't be able to do what we do without them.

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

Thank you, sir. (Operator Instructions). Our first question comes from John Fitzgerald with Raymond James.

Good morning. Well, obviously there is a discrepancy between the terms of the contract rates and spot market rates right now, and I'm trying to get some more color on that. Could you kind of go through where rates and margins are trending on your term contract rates during the second quarter? And if you see that changing at all going forward, as you deploy some of the new APEX rigs?

In terms of term contracts, term contracts in place early in the year were primary from periods prior to 2008. The rigs coming out that were contracted in 2008, which are coming on line now, were at somewhat higher margins. The day rates of those contracts vary, but generally they're in the mid-or-upper 20s, and the costs of running those rigs aren't significantly different than the cost of other rigs. So on the term contract side, a slight movement upward in terms of the margins per day versus what we saw, say, a year ago.

Okay, and versus the second quarter?

Beg your pardon?

Not much changed versus the second quarter?

Really, John, I don't think anything has changed in the second quarter. Those term contracted rigs, most of the deals were done a year ago, and the numbers that John quoted were, in essence, the numbers that those rigs are coming to the market at.

Okay. And then in terms of the spot rates, are you guys you know -- you have notice -- you noted last quarter that they were kind of all over the board. Is there much of a difference now -- what you're seeing between -- you know some of your older mechanical rigs and the larger, newer service rigs that you guys have? Is there much of a spread there, or is it kind of -- spot rates across the board have all kind of leveled out?

Well, I think spot rates are somewhat geographically dependent, and somewhat geographically dependent on the class of rig, but certainly geographic rates, in places like Oklahoma and Texas, typically are lower than some other markets, say Haynesville or East Texas. Interestingly enough, I think spot market rates, there really isn't a whole lot of difference between either new rigs, newly refurbished rigs or existing rigs. You know, we've heard people comment that there is still is a significant difference in the spot market. There is some difference, but it is certainly narrowing.

Okay, great, thanks sir.

The next question is from Dan Boyd with Goldman Sachs.

Thanks, good morning.

Good morning, Dan.

This question is for Mark, but if we take a step back and we look at you know you are cutting costs, you're doing the best to manage the business in the down turn, but what level of rig activity or -- either overall in the Baker Hughes rig court, or for Patterson specifically, do you think will be required before the Company will be able to break even at the operating income level?

You know, Dan, we have been reluctant to say much more than looking out one quarter in these conference calls, and that is because of the extreme volatility in the land drilling industry. And you know I remain pretty steadfast about that kind of a view, and starting to look forward multiple quarters is kind of a challenge for us. I mean, frankly, you know there are so many moving parts in our business in terms of what would drive us from the loss that we experienced in to just reported quarter to a profitable quarter, and you could imagine those happening for any number of reasons depending on what the circumstances were. So I'm reluctant to say much more than what we're looking for in the third quarter, and unfortunately we're not seeing a return to net income in that quarter.

How about on the operating income line for contract drillings. Should -- if things stay where they are today, maybe a couple of rigs go back to work, do you lose a little money in the third quarter operating income-wise?

Let me head somewhere else for a moment, realized we scaled our business to take advantage of the down turn, to try to create any -- fix any inefficiency that has occurred over the last six or eight years of a high level activity. At the same time we maintained the expertise and ability to bring back all of our rigs. So to say that our drilling business is running at perfect efficiency, it is not; we would scale the business down further if we believed long term we were going to be running 60 or 70 rigs. So we're maintaining that expertise, which in the short term would contribute to losses.

So when you ask the question at what level do we get profitable, it is interesting one. We're anticipating an upturn at some point in the future, where we run more rigs, and we're maintaining our expertise in the meantime.

Okay. I guess I'm just looking if we were expecting to be running 100 -- say you even triple the rate count here, and you get up to -- you know 175 or 180 rigs, depending on -- I feel like the industry utilization would still be at a pretty low level, so I'm not sure how much pricing power there would be, but would you anticipate to be at a profitable level at that point, as you scale the business?

I haven't done the specific math. I mean, as we look into the third quarter, you know I think given the information we have already provided in the opening remarks that we're going to have actually less operating income in the drilling business than we did in the second, simply driven by more rigs running at the spot rate.

Yes. Okay, thanks I'll turn it back over.

The next question is from Geoff Kieburtz with Weeden.

Good morning, thanks. Couple of questions. The increase in the active rig numbers for -- currently versus the month of June, can you tell us a little bit about where those rigs are going back to work? And what type of rigs they are?

Yes -- Jeff, you know it is a little bit of a mixed bag. But if I had to generalize, I would say that the rigs that are going back to work today, there is a few of them in West Texas and there is a few of them in Oklahoma. The rest of them are kind of scattered throughout the regions. But interesting enough, it is some of our older legacy-type rigs that are going back to work. So you know we felt know with crude oil prices above $60, we felt a little bit of activity in the oil producing basins. And obviously those are places like West Texas and the [Bocan]. So as I said, it has been kind of interesting, it is some of our older mechanical legacy rigs that have gone back to work in some of these markets. Now obviously the other thing is the rigs we bought back to market, and most of those rigs are going to the -- today, they're going to Haynesville and the Marcellus.

Right, so the legacy rigs, would it be fair to guess that most of the legacy rigs are going back to work drilling for oil?

It is actually almost 50/50.

Okay.

I think what has happened, Jeff, is that service costs, and I'm not just talking about the drilling costs, have now come down to a level that even with these commodity prices some of the smaller independents are saying hey, my pay backs are not that dissimilar to what they were when the service costs were so much higher. So we're seeing a lot of the little guys sort of that drill the two to three to five wells a year looking at their costs and looking at their pay backs, and saying now is as good a time as any. We're at a point where service costs are probably as low as they're going to be for some time.

Not to get too granular here, but you had 58 rigs working in the U.S. in June. I think -- what is it, 66 now?

66.

So four of those presumably are the APEX rigs that you put out in the field, right?

Yes.

The four other rigs, can you give us a sense of what the day rate is on those four rigs?

Well, let's put it this way. They're -- certainly lower than the average. They're in a -- they're in a position that we're you know --

Jeff, it is Mark Siegel. Let me say -- I think the best way for you to think about that is to say that we expect that the spot rate market will be approximately 12,000 to 12,500.

Okay.

On average. And there is going to be some above it and some below it. And so if you use that 12,000 number, right now, and maybe even a little more -- but that 12,000 number, you're going to get to kind of what we think. And frankly, you know if you pick any one or two rigs you're going to have something -- the numbers -- are not at -- a good average.

Sorry, go ahead.

I was going to say just to add to that, we had said last conference call, and I guess we would say it again, there really has not been much of a spot market. So when you start looking at these one-offs to kind of say that's what the spot market is today, I think it is a little misleading.

Sure, I understand that. Given that limited set of data, do you feel like that 12,000 to 12,500 is reasonably stable as you look out over the next three months or so?

Well, I think it is, obviously it is supply and demand. We think the rig count, if it hasn't bottomed it is certainly very close to the bottom. And I think it just depends on the individual markets. It depends exactly what equipment the customer is looking for, it depends on how many of those kinds of rigs are available in the market. And in a lot of cases, it depends on the customer and the relationship you have with that customer.

And you commented that you expected average costs per active rig day in the third quarter to be a little over $11,000, compared to just under $10,000 for the second quarter. What -- why is that?

Well, we -- quite honestly there was a couple of one-off items that affected those numbers in really Q2. We don't think we're going to have as many stand by days, and we don't think -- you know, that actuarial adjustment on our workers' compensation costs is kind of a one-time, once-a-year kind of event.

We'll also have more rigs working in Canada, which has a little bit of an impact also.

Okay. Great, I'll let somebody else ask questions. Thank you.

Your next question is from Arun Jayaram with Credit Suisse.

Good morning, guys.

Good morning.

Very impressive on the cost side, how you were able to illustrate the variable nature of your cost structure. I had a couple of questions regarding your fleet today. Can you give us a sense -- you have made some investments in the APEX rigs and Walking rigs. Can you give us a sense today of how many of your rigs do you think are at the upper end of the food chain in terms of you know, high-end capabilities?

You know I would say that we have more than 100 rigs that we would say are competitive with anybody's rigs. And that are -- you know top flight SCR and AC electric rigs. So we think that first 100 rigs, that I think sometimes the Street overlooks, are among the best rigs in the entire land rig industry. Included in that group are, as you said, the APEX rigs, both the APEX 1500s and the APEX 1000s, as well as the APEX Walking rigs, which we think are among the most technologically -- superior, advance technology rigs in the industry. So I hope that is kind of an answer to the question you were looking to get answered?

That is helpful. And can you remind us, between the Walking, and APEX 1000 and 1500, how many in each category you have?

Well, by the end of the year we'll have 18 of the APEX 1500s, eight of the APEX 1000s, and the difference -- 23 of the APEX Walking rigs.

Okay, that is very helpful. Second question is guys if the rig count were to normalize, this is more of an industry comment more than a Patterson comment, in the 1,200 to 1,300 range, somewhere in that range, where do you think margins industry-wide would be on a blended basis?

Well, that is kind of a tough question. You know you almost got the break it down into the various components. If the rig count -- if you said that the industry today has potentially -- you know, I'm going to say between 400 and 600 of the truly advanced technology rigs?

Right.

And if you assume that they all go to work, which may or may not be a fair assumption, but most of those rigs at least have come to market with some sort of a term contract. So let's assume that they work. Well, if you have got 1,200 or 1,300 rigs, so then you got a second category of somewhere between 600 and 800 rigs from the rest of people's fleets. And I guess at that point you know I think the shale plays particularly are going to demand a type and quality of rig that you're going to bet a better margin on, just because of the results and the -- the kind of technology the customer wants, and its ability to move. And I think that -- at 1,200 or 1300 rugs, a significant number of what I'm going to call the rest of people's fleets are going to be back working, and depending where they go to work I think will impact what those margins look like.

And also I would say that the quality of the crews, and the ability to do the work very efficiently for the customer, will be something which we think will be rewarded by the marketplace, and we think we'll be able to generate some incremental benefit from that.

Okay, that is interesting. Last question is ,one of your peers had indicated that they're seeing about a $5,000 deviation from, call it commodity rigs and higher end rigs. Are you seeing similar types of deviations? And do you think if the rig count stays relatively range-bound in the near term, you know, maybe up a little bit, do you think that $5,000 type of difference is sustainable?

You know, we have seen certain situations in which we have been able to get a premium for a rig because of the customer's unique needs and the rig's unique qualities. But generalizing across the entire fleet at this point to say that we think there are, we think, $5,000 differences between the most advanced technology rigs, not under term contract in the other rigs, seems to us to be a challenge as an overall generalization.

That is helpful. Thank you.

Maybe specifics, but not a generalization.

The next question is from John Daniel with Simmons & Company.

Good morning.

Good morning.

Just two question questions for you guys, the first is some of your competitors have talked about the fact that they have had to amend their term contracts, lowering day rates for extend terms; is that something you have had to do yet?

Well, we get all sorts of pressure, as they mentioned on our last call, we had 22 new rigs this year. Believe me, we have had conversations with all 22 of those customers that are taking new rigs, and certainly most of them have asked for some sort of concession. But the contracts are very clear, they're virtually take or pay contracts.

We have made a very limited number of modifications, not so much to day rates but to some of the terms and actually delivery dates, to try and accommodate our customers. But we look at them on a case by case basis, and quite honestly we try very diligently -- if we're going to make any concessions whatsoever, we get something in return either on the back end of the contract as an extension or some other rigs put to work to really compensate us for anything that we've done for them.

But for the most part, like I said, we really have -- they all ask, but quite honestly we really have not backed off the terms of those contracts.

Okay. Any chance you guys could quantify the actuarial adjustment for us on the drilling costs?

For the quarter on a per-day basis, that would have been somewhere towards $300 a day, a little less than that.

Okay. And then last but not least, I don't know if you said this on the call or not, but what the committed CapEx is for the balance of the year?

Well, our CapEx for the year we think still will be very close to $500 million. To date, we have spent about $250 million. So we're right on track through the half of the year.

To give you some specifics, to the end of June we have spent approximately $170 million on the new rigs, approximately $25 million on the rig upgrades, $20 million on maintenance capital, and a further $30 million in our pressure pumping business. And the rest of it is -- kind of -- other, but very small. Year-to-date, we're about $250 million and we expect we'll come out pretty close to the $500 million that we had originally talked about.

Okay, thank you very much.

Your next question is from Mike Drickamer with Morgan Keegan.

Hi guys, I only have a quick question for you. Looking at your current [leg], how many rigs do you think you could operate right now?

Well, I guess we look at the world as rigs, and people who are not on rigs, and in terms of rigs we do not maintain additional people. Now within the current rig labor pool there are people who, you know, just nine months ago may have been superintendents or tool pushers or drillers, who are at different levels today, so that we can maintain our expertise, but we do not maintain any significant workforce over and above what we need to run the rigs.

The comments earlier about being prepared to run more rigs relates to maintaining the -- the yards and the facilities that will allow us to operate a greater number of rigs in some of these markets. You know, realize you don't need the size yards we have if you were just going to be a 60 or 70 rig contractor. So that is where the inefficiency is, it is above the rig.

So if I understand correctly, every time you reactivate a rig, you have to go hire a new crew?

Well, hire some components of the new crew. We typically would -- the original rig manager might go back to his rig. The drillers would likely go back to the same rig. We would be recalling people that had potentially worked on the rig before. You know as an industry, we're down almost 1,000 rigs; if you have assume that 20 people really on each rig lost their job, there is a market for us out there today of 20,000 to 25,000 people that are waiting to go back to work in this industry.

Though -- we, you know -- we keep constant lists of who our best people are. Trust me, we get more calls and our HR people get hounded every day about when is my rig going back to work. So to answer your questions, we feel that given enough time and some advance notice, we would have very little difficulty getting back to a reasonable amount of rigs running, but you can't do it all at once.

What do you guys find as a reasonable number of rigs running?

Well, my point is I guess would be I think you could probably put out somewhere 10 and 20 rigs per month. If we had to, we could do it quicker than that. But if think we want to make sure that we do things appropriately, and have both the equipment and the people properly trained, to make sure that we do our good job for our customer.

Okay guys, that is all for me, thank you.

Your next question is from with Waqar Syed with Tristone Capital.

Good morning. Do you have any guidance for us for 2010 CapEx? Do you think once this current cap billing program ends, are you going to, you know, start a new one, or this is it for you guys for now? Or how should we be thinking about 2010 CapEx?

Waqar, at this point we haven't finalized our plans for 2010. You know -- I think certainly we would continue to spend a little bit of money on upgrading and doing, you know things to make our rig fleet a little bit better. But in terms of new-built program, it is just a little bit early in the year for us to look beyond the 20-plus rigs we have already talked about, and I think over the next three months we'll try to finalize those plans.

Okay. And then on -- in terms of consolidation, do you see consolidation opportunities in the market, you know -- if you're looking to by assets, you know, there are a number of assets in the market today, maybe perhaps some older equipment. Would you have any interest in consolidating now some of the older equipment, or are you now focused primarily on the upgraded and new rigs?

Waqar, I think -- you know, for more than 10 years now we have been value buyers of equipment. And we just look at what we get for the dollars, where we would have to spend. I think of anything I'm familiar with, frankly the -- the cost has exceeded what I see as a good value for us. We don't need to further consolidate, given our large rig fleet and large presence across the country. But if there is, you know, great opportunities out there we certainly would look at them.

Okay. And this -- finally, any opportunity that you see on the international front in moving rigs out of the U.S. into the international markets?

Well, again Waqar, we have looked at a lot of international opportunities in the last little while. I think actually the land drilling business internationally has also become very competitive. There is -- I think utilization rates are down nationally. The one that obviously has been of a fair amount of interest to us is Mexico. We have bid a number of situations in Mexico. So far we have been unsuccessful. But we will continue to look to see if we can find the right opportunity.

Sounds good. Thank you, sir.

Your next question is a follow-up question Geoff Keiburtz with Weeden.

Thanks. Pressure pumping margins per job look like they picked up a little bit in the second quarter from the first quarter. I know you gave us a little bit of near-term guidance, but can you elaborate on what is going on there?

Jeff, it is really just mix, historically they have done a lot of small traditional jobs in the Appalachians, and there has been a move towards these larger horizontal fracs, and mix will cause some bumping around the margins that may seem a little bit inconsistent with what is going on in the marketplace. I think we also mentioned, they're getting about 5% less on a book basis, but some of these bigger jobs have a little higher percentage margin.

Okay, and as we look into the second half of the year, I think your commentary suggested sort of a second quarter run rate, you expected it to sort of sustain itself in the second half?

You're talking specifically pressure pumping?

Correct.

We actually think we're going to see a little bit of an uptick in Q3, and then Q4 probably will be somewhat similar to Q2. Q4 in that marketplace we get some seasonal issues that is always a little bit hard to predict, but we do anticipate that we're going to see more horizontal completions up there in both Q3 and Q4.

Okay. And the uptick in the quarter would primarily be activity, but margins would stay pretty much where they are?

Yes, similar, I think -- as you look at the back half, I think your starting statement was fairly accurate, in the sense the third quarter we see it being, you know, somewhat better than the second. But fourth quarter with shorter days and less days to work given the holidays, that may we'll offset that retick to six months together, and I think yes, it probably looks pretty similar to the first half.

And on the fluids business, maybe a little deterioration from the second quarter run rate?

Yes.

Okay, and again both on the revenue and the margin side?

Yes.

Okay. Thank you.

(Operator Instructions). The next question is from John Keller with Johnson Rice & Company.

Good morning. A question. You know, the Baker Hughes rig count is down about 1,000, I guess, from its peak, although we've seen a bit of an uptick recently. My question is around rig attrition. I mean, do you have any sense of what is going on out there in the industry for people actually cutting up some of those 1,000 that have lost jobs?

We really don't have much of a feel for that, I have not heard of a lot of people actually cutting up rigs. I know in our own case, I think in the short term that would be rather foolhardy. If you look at our own fleet, quite honestly all of the rigs that we've got in a lot of our categories have worked in the last two or three years and have made us a lot of money. I don't know why anybody today would be making that decision to physically cut them up, unless they were just in such bad shape they just couldn't run.

So there may be some people out there thinking about it. But I honestly don't think it is -- it is too early in this process, and I don't think anybody has any idea of how long this will last. And I think if you have got assets that you can get a good return on, why would you be cutting them up?

No, makes sense. I had just heard anecdotally of some of that going on, so I was curious if you had any sense of what it was. That was my last question, I'll turn it back. Thanks.

(Operator Instructions). Your next question is from Jamie Stone at Barron Capital.

Good morning, guys. I just -- pursuant to the last question, not so much a function of cutting up rigs, but can you talk about the extent to which you guys may be saving on capital by cannibalizing parts or drill pipe off of idle equipment, and how you see that playing out over the next several quarters with -- you know if the rig count stays, you know, at current levels, plus or minus 50 rigs?

Yes, let me make one comment. Then I'll turn it to John for a little elaboration. My comment would be that I think that Patterson-UTI has somewhat of an industry unique position with our cash and debt-free position, such that we have been able to maintain our rigs, and to in effect go forward, and we have done this historically over many years, such that we haven't had to, in effect, take parts, take things and so on and so forth. That is not to say that when we don't have good opportunities currently to, in effect, use our equipment in the most beneficial way, we won't use it.

But I think the point that the last question was sort of directed at, and potentially your question is directed at is, may there be some of the rigs that are being shut down by other players that will not be able to come back to market, because in effect they have been cannibalized? We can't speak to that. We don't see it. In terms of our own equipment, we're doing very little of that. John?

Yes, the only thing I would add, if you look back over the last couple of years, you might recall that in early 2007 we took a hard look at the rig fleet, identified rigs that had not worked in 2006 in a very strong market, and ceased to refer to somewhere around 40 of those rigs as rigs, and if you went to our yards, some of that equipment is still there and, you know, cut up so it can't be reused and turned into scrap. So we went through a process particularly in 2007, and going forward our operations people continually look at our rigs to determine whether they believe that those have opportunities to make money.

There is a little bit of retirements in 2008, around 20 rigs. Since that time there really hasn't been much. I think there was -- two rigs got combined to generate a better rig. But overall, I don't think we expect any, you know, big change in our rig fleet from here.

And would that comment hold if we were sitting here in the second quarter of 2010 and still running, you know, 700 -- you know -- at the current level of rig count on shore?

I think the question is still the same, it is always do you have an asset there that can return to work, as Doug talked about earlier. You know, there is not a lot of book value associated with many of those rigs. There is not a lot of costs to store them. They are not on expensive real estate. You know, so therefore it is always a question, can we generate enhanced returns for shareholders by keeping that asset?

So implicitly then on the 60, 70 rigs that you have got working, you're saying -- you know, you're buying enough capital in spares to keep those rigs working from an OEM, as opposed to taking them out of quote/unquote inventory? The plan is to at least operate in that manner if this lasts, you know, another 12 months or so?

Generally true, you know certainly if a piece of equipment fails in the field, and we have another one, whether it is a spare or on another rig, that can be quickly put out there so we can keep generating revenue, you know we're -- I feel certain our operating people will do the right thing, and that is keep the revenue stream going, but that is not a decision to cannibalize rigs, that is just trying to operate efficiently, and we do that in good or bad times.

And you would replace that piece of equipment?

Yes, the one that got broken down would be sent in to be fixed.

Right. Okay. Thank you.

The only thing I would say is repair or replace.

Yes. Thanks.

Sure.

(Operator Instructions). As there are no further questions in the queue, I'll hand the call back the management for closing remarks.

Just like to thank everybody for their participation in our call, and look forward to speaking with everyone at the end of our third quarter. Thanks, everybody.

Ladies and gentlemen, we thank you for your participation in today's conference. This concludes the presentation, and you may now disconnect. Have a good day.