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Executives

Jeff Lloyd – Media Contact

Mark S. Siegel – Chairman of the Board

Douglas J. Wall – President, Chief Executive Officer

John E. Vollmer III – Chief Financial Officer

Analysts

John Fitzgerald – Raymond James

Jeff Tillery – Tudor, Pickering & Holt

Ben Dale – Bernstein

Arun Jayaram – Credit Suisse

Mike Drickamer – Morgan Keegan

Dan Boyd – Goldman Sachs

Andrew Coleman – UBS

John Dan Yells – Simmons and Company

Todd Garman – Peters & Company

John Curber – Bennett Management

Patterson-UTI Energy, Inc (PTEN) Q3 2008 Earnings Call October 30, 1969 4:00 AM ET

Good day ladies and gentlemen and welcome to the third quarter 2008 Patterson-UTI Energy Incorporated earnings conference call. My name is Tawanda and I will be your coordinator for today (Operator Instructions). I would now like to turn the presentation over to Mr. Jeff Lloyd on behalf of Patterson-UTI Energy. Sir, you may proceed.

Jeff Lloyd

Thank you. Good morning and on behalf of Patterson-UTI Energy I’d like to welcome everyone to today’s conference call to discuss the results of the three and nine months ended September 30, 2008. Participating in today’s call will be Mark Siegel, Chairman, Doug Wall, Chief Executive Officer and John Vollmer, Chief Financial Officer.

Again, just a quick reminder that statements made in this conference call will state the company’s or management’s intentions, beliefs, expectations or predictions for the future are forward-looking statements. It’s important to note that actual results could differ materially from those discussed in such forward-looking statements.

Important factors that could cause actual results to differ materially include, but are not limited to declines in oil and natural gas prices that could adversely affect the demand for company services and their associated affect on day rates, regulazation and planned capital expenditures, excess availability of land drilling rigs, including, as a result of the re-activation 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 these 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.

Again, the company undertakes no obligation to publicly update or revise any forward-looking statements. Now, it’s my pleasure to turn the call over to Mark Siegel for some opening remarks to be followed by questions and answers, Mark.

Mark S. Siegel

Thank you, Jeff. Welcome to Patterson-UTI’s conference call for the third quarter of 2008. I wish you all a good morning and thank you for joining us today. I trust by now all of you have had an opportunity to read our earnings release, which was issued earlier this morning, prior to the opening of the market.

I plan to begin by taking a couple of minutes to review briefly the financial results for the just-completed quarter. I will then turn the call over to Doug Wall, Patterson-UTI’s President and CEO for some comments and color on our operating results.

After Doug’s comments on the quarter, I will make a few comments on the market outlook even though we have very little clarity at the present time. As always, we will be pleased to take your questions following these prepared remarks.

Today, we reported net income of $109 million or $0.70 per share for the three months ended September 30, 2008, compared to net income of $98.2 million or $0.62 per share for the three months ended September 30, 2007. This represents an 11% improvement year-over-year.

Revenues for the third quarter of 2008 were $609 million, compared to revenues of $524 million for the third quarter of 2007, a 16% improvement.

For the nine months ended September 30, we reported net income of $268 million or $1.72 per share. This compares to net income of $354 million or $2.24 per share for the nine months ended September 30, 2007.

Revenues for the first nine months of 2008 were $1.64 billion compared to revenues of $1.59 billion for the first nine months of 2007. Once again, I wish to remind you that the results for the nine months ended September 30, 2007 include pre-tax, non-recurring gains of $59.6 million, resulting from the sale of certain E&P assets and the recovery of embezzled funds. These gains, net of taxes, increased net income for the nine months ended September 30, 2007 by $38.7 million or $0.25 per share.

During the quarter, we re-purchased 2 million shares of the company’s for an aggregate purchase price of $50 million. Although the current price for the company’s is well below the level at which we purchase shares, we believed and continue to believe that at an approximate price of $25.00 per share, we were obtaining a good value for the company.

This price reflects a decline of 33% from the price of the company’s recent high. The company still has authorization to re-purchase a further $129 million worth of stock under our most recent authorization from the board.

And finally today, I am also pleased to report that our board declared a quarterly cash dividend on our common stock of $0.16 per share to be paid on December 30, 2008 to holders of record as of December 12, 2008 based on our closing price on October 29th of $12.32. Our stock has a current yield of 5.2%, which we believe to be among the highest yields achievable in the energy services sector.

I would not like to turn the call over to Doug Wall for a discussion of our operating results for the quarter.

Douglas J. Wall

Thank you, Mark. I’d like to make a few brief comments on the operating division, starting with the drilling company. For the quarter ended September 30, 2008, the company had an average of 276 operating, up 32 rigs from Q2. The rig count for the quarter averaged 264 rigs in the U.S. and 12 rigs in Canada. By comparison, a year ago, we averaged 234 in the U.S. and nine in Canada.

Our drilling activity accelerated nicely throughout the quarter. On average, 269 rigs operated in July, the count jumped to 278 in August and further increased to 281 rigs working in the month of September. For the first three weeks of October, this growth continued this upward trend and only in the latter stages of the month have we seen any small drop off in the rig count.

We were very pleased by the expansion in U.S. rig count of some 40 rigs this year, further testament to our belief that our rigs are quite capable of providing valuable services for our customers as well as operating efficiently and safely. In fact, we expect we would have seen even further growth in the number of rigs if not for the precipitous decline in commodity prices and the recent collapse of the credit markets.

Overall, our drilling business had an excellent quarter. As was expected, our Canadian utilization improved during the quarter, coming off the seasonal lows during Q2. We averaged 12 rigs working gin Canada for the quarter and anticipate we will stay in this range throughout the remainder of the year. We have geared up for a very busy winter drilling season in Canada.

Overall, average revenues per operating day during the third quarter were $19,620, compared to $18,740 in the second quarter; a very nice improvement, $880 per day.

Average direct operating costs were $11,130 for the third quarter, down $170 per day from the $11,300 we experienced in Q2. Overall, our gross margins improved by $1050 per day from Q2.

At the end of the quarter, we have 54 rigs working under term contracts, which had an original term of a year or more. At the present time, we have 25 additional term contracts for new-build rigs that will be activated over the next five quarters.

Let me talk about a few of the operational highlights for the quarter. We introduced five new rigs to the market place during the third quarter, three of which were our new APEX 1500 rigs. Two of these rigs were deployed in the Barnett Shale and the other in the Haynesville Shale.

We also introduced another of our highly successful walking rigs in the Rockies. This brings our total fleet of walking rigs to 12 rigs, with another ten to be deployed over the next five quarters. In total, through the third quarter of this year, we have introduced 11 new rigs to the marketplace, all of which are operating very efficiently and at very attractive rates and margins.

I should point out that we have now branded our new, advanced technology rigs the APEX Series. From this point on, you will hear us refer to all of our new, advanced technology offerings as APEX rigs. For example, the new 1500 horsepower rigs we have been introducing throughout this year, which we have formally referred to as Ideal rigs, will now be known as APEX 1500.

Our newly designed, advanced technology rigs that were specifically designed for small locations, such as we find in the Appalachians, these rigs will be known as APEX 1000’s and finally, all of our highly-acclaimed walking rigs will now be known as APEX Walking Rigs.

We anticipate completing an additional six rigs in Q4. Four of which will be the APEX 1500’s, the other two will be APEX Walking Rigs. All of these rigs will be deployed in either of the Barnett Shale, the Haynesville Shale of East Texas and North Louisiana or the Resource Plays in the Rockies.

Over the next two years, we now expect to construct 34 new advance technology rigs. Of these, 24 have been contracted on three year terms and one on a two year term; all of these with very favorable pricing.

With our industry-leading APEX Walking Rigs and all of the new builds for both 2008 and 2009, we will exit 2009 with approximately 60 new state-of- the-art APEX drilling rigs. In addition, we have also a substantial number of rigs that have been totally refurbished over the last three years.

We expect that the addition of these new rigs, together with the refurbished rigs, will certainly help to mitigate the impact on Patterson-UTI of the decline in overall rig activity in margins we may see in the coming months.

Let me turn now and make a few comments about our pressure-pumping business, Universal Well Services. As expected, business levels in the pressure-pumping business in Appalachia improved during the quarter. Revenues for the third quarter of 2008 reached an all-time high of $60.6 million, up over 6% sequentially and 4% higher than the same quarter a year ago.

The number of jobs completed improved by 9% sequentially, but it is down 8% from the record number of jobs we completed in the same quarter a year. Average revenue per job declined somewhat on a sequential basis to $16,240, reflecting a slight change in our job mix. We certainly did more cement jobs and slightly few frac and nitrogen jobs.

Activity levels have not been as high as we originally anticipated in this market, primarily due to delays in permit approvals for use of land and water resources. We do, however, that these are delays and do not reflect any less enthusiasm for the long-term development of the Marcellus and Huron Shale Plays.

Operating margins in this division are still be impacted by high fuel and sand costs as well as additional labor costs as we geared up for the expected increase in business, driven by activity in the Marcellus Shale.

In terms of capital, we spent $18 million on new pressure-pumping equipment during the quarter, with a large amount of that directed towards upgrading our fracturing capabilities. We have now taken delivery of five of our new 2,250 horsepower Quintaplex pumps that were specifically purchased for horizontal fracs in the Marcellus. We will have five more of these units delivered prior to the end of Q4.

We expect all of this additional equipment this year to drive significant growth.

Turning now to the drilling fluid segment, as you might have expected, Ambar Lone Star was significantly impacted by both hurricanes Gustav and Ike. Revenues were down over 8% sequentially as our operations were suspended for over 20 days at most of our Gulf Coast facilities.

Our facilities at Cameron, Inner Coastal City and Galveston all experienced damage. However, I am pleased to say we’re now back up and running.

Margins in this business continue to be very thin as cost increases in barite fuel, raw materials as well as labor costs, continue to put pressure on our margins. We do not see any meaningful change in this business in the immediate future. And with that, I’ll now turn the call back to Mark for some concluding remarks.

Mark S. Siegel

Thanks, Doug. As Doug’s comments reflect, we saw a major step change in our drilling business in the third quarter, with accelerating demand for both new and existing rigs. As we had discussed in prior conference calls, we had expected this change based on strong commodity prices and in particular, natural gas prices at $8.00 or higher.

But, what a difference I’ve seen in the last 30 days or so. I’m not sure I’ve ever witnessed such a dramatic change in the business climate in such period of time. The combination of falling commodity prices and the general turmoil in the credit markets, coupled with uncertainties surrounding the U.S. election, have given rise to an unprecedented decline, not only in the stock and capital markets, but also in consumer confidence.

Personally, it’s like a plane hitting an air pocket, you keep waiting for the plane to reach a level altitude at which smooth flying resumes. Although we don’t really have a lot of clarity as to where all of this is headed, several things are becoming more clear.

Assuming that commodity prices stay at depressed levels and credit markets are constrained, our customers certainly are going to have less free cash flow in 2009 as well as less access to capital. This is bound to have an impact on rig count in both the U.S. and Canada. Right now, it seems impossible to assess the likely magnitude of the decline or it’s expected length.

As we said in our press release, we expect our rig count will be 283 for October, up two from September. We believe, however, that based on a reduction of activity by reason of the holiday season and based on input from our customers, that our total rig count for the fourth quarter will be in the low 270’s, including approximately 12 rigs running in Canada.

We expect that margins during the fourth quarter will remain flat at approximately $8,500 per day.

Having said all of this, it must be pointed out that natural gas prices in the $6.00 to $7.00 range are not that bad. In fact, those prices are very similar to the prices we had one year ago. We do know that at these prices, approximately 1,700 rigs were working in the U.S. a year ago.

Will it get worse than this? We really don’t know, but we must keep things in perspective. We believe that any major decline we see in drilling activity will result in a pretty quick decline in the supply side of natural gas. Subject to what happens on the demand side, we believe that any major decline in production will like result in lower supplies and a result in increase in prices, thus ultimately driving more drilling activity. We refer to this as the Virtuous Cycle.

Although it may take some time for the world’s economies to recover from this crisis, we do believe that in the long term we will continue to have to drill more wells to meet the demands of consumers and the economy in general.

Moreover, we believe that the high depletion rates of current gas wells will inevitably mean that a decrease in drilling will quickly lead to a substantial decrease in supply. Indeed, our recent experience with commodity cycles, albeit without the sturm and drang of the current crisis, are shorter and less steep, due to this acceleration in depletion rates.

As a company, we are taking steps to prepare for a decline in the rig gap, whether modest or sharp. We are taking a hard look at our cost structure and we will re-evaluate our discretionary capital expenditure program.

We believe, however that our debt-free balance sheet puts us in an enviable position to increase share holder value during this downturn. That said, it won’t be painless, but we are better-positioned than ever to respond to these difficult times.

Before concluding, I’d like to take a moment to address our stock prices. Like so many investors, I am frustrated at the valuation accorded to our company. I had expected that with our balance sheet, with no long-term debt, net, plant, property and equipment of more than $1.9 billion and current assets of more than $600 million, together with our yearly annualized dividend of $0.64 per share, would assure that our stock price would not fall to the current level. Of course, like others I am surprised by the depth of the economic crisis we currently find our country.

Before we open the call to questions we would like to take this opportunity to express our sincere appreciation to the employees of Patterson-UTI. We have survived and thrived during tough times before and it is the dedication and resolve of our people that will help us to continue to succeed. We will now open the call for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Your first question comes from the line of John Fitzgerald with Patterson. Please proceed.

John Fitzgerald – Raymond James

Good morning guys, it’s actually Raymond James but. On the drilling side I guess costs were actually down during the quarter, maybe some help from lower fuel costs and I don’t know if you were still deploying some of your stacked rigs. But can you guys describe how you’re able to control costs so well and where you see that going over maybe the next quarter or two?

John E. Vollmer III

Yes, this is John Vollmer. In the second quarter we expended quite a few dollars activating rigs and Doug mentioned earlier, our U.S. rig count during the first nine months was 40. It was higher than it was at year end. We – as we went into third quarter it was a little bit unclear to us whether we would get savings in the third quarter or if it would occur in the fourth. But most of the reactivation cost did occur during the second quarter resulting in an improvement in our average cost per day.

We also had, in response to some other drilling companies we increased wages for rig employees right in the third quarter so that actually contributed somewhere toward the $100 in increased costs. So without that we would have been closer to 11,000 or so in cost per day in the third quarter.

Looking forward to the fourth quarter we’ll see the rest of that increase which is approximately $500 a day and that would take our per day costs in Q4 to about 11,500. And also since those costs are a direct pass through to the customers we’ll get a little bit of benefit in the average revenue per day side and we would guess that that would be somewhere around 20,000 in Q4.

John Fitzgerald – Raymond James

Okay. Thanks for the color. And then I guess bigger picture, you guys have a clean balance sheet. We’re thinking next year might be a good chance for consolidation in the market. Is that a possibility for you guys? Are you still inclined to stick with the new bills and put out your Apex rigs? Or are you still just thinking stick – maybe even just go on to refurb side? Axe what you’ve already planned putting out in the market.

Mark S. Siegel

No, this is Mark. Our view about this is that we continue to look at all possible transactions that are presented to us. From our perspective you have to consider the quality of the assets that you can obtain in every given transaction as against the price. Over the last few years we’ve thought that the best things we could put our capital into was the refurbishing of our existing rigs, our new rigs, and our stock buyback, and our dividend. And that’s in fact what we’ve done. We’re very proud of that record. We think that was the good way to deploy capital, a smart allocation of resources. But we will continue to look at transactions into the extent to which that makes sense we’ll consider them.

John Fitzgerald – Raymond James

All right, thank you.

Operator

Your next question comes from the line of Jeff Tillery with Tudor, Pickering & Holt. Please proceed.

Jeff Tillery – Tudor, Pickering & Holt

Hi good morning.

Mark S. Siegel

Good morning.

John E. Vollmer III

Good morning.

Jeff Tillery – Tudor, Pickering & Holt

Recognizing that there’s a lot in flux right now and ’09 capital expense plans will certainly move around a bit, could you walk us through how you think about maintenance capital and then what is committed for 2009 for the new build program already?

Mark S. Siegel

Let me respond to that in the following way and turn it over to John for a little bit of color. We’ve had a long-term program as you know of refurbishing rigs, of when customers sought specific fit-for-purpose rigs, building fit-for-purpose new rigs – those are our walking rigs. We’ve also had the Apex 1500 rigs which we formerly called ideal rigs which we bought in 2006 and have been putting out into the market this year. So we’ve had a long-term program of building new rigs when customer demand required it to meet specific needs for our – of our customers.

We’ve continued that program and expect to continue that program into 2009. That said our – in previous conversations with previous conference calls we’ve indicated that we expected our CAPEX budget next year to be approximately $600 million. That being said, that was before we had our annual budget cycle. We’re in the process of our annual budget cycle right now. We will do as a company operating as well as capital budgets. Those will be presented to our board later on for the boards review and approval. And we may increase or decrease that $600 million going forward depending on what we see.

With that – and obviously as I said in my prepared remarks, we’ll be taking a hard look at discretionary capital. With that I’ll turn it over to John for the maintenance capital comments.

John E. Vollmer III

Yes, we – for maintenance capital we’ve actually experienced decrease in cost per day. But historically we’ve used about $1,000 per operating day for maintenance capital. Of late it’s been a little lower than that. On that basis I would think maintenance capital for next year would be somewhere towards $80 million. And as we finalize our budget if we continue the expansion of the pressure pumping business, I would guess somewhere toward $50 million like that in the other businesses. And with a not yet completed budget but guess of capital next year around, 600 million, that would leave 470 million of new rigs and upgrades of other equipment.

Jeff Tillery – Tudor, Pickering & Holt

Okay. Thank you for that. I just want to make sure I have the numbers clear on the incremental new builds versus what you guys talked about on the second quarter conference call. How many of the 34 were incremental versus the last time you guys talked about it?

Douglas J. Wall

Jeff, that number is probably eight. The 34 that we talked about is really from this point forward which includes about six of the previously announced 1,500 horsepower rigs that we had announced a couple of years ago. So the real number that I guess over what we told you last quarter was eight rigs.

Jeff Tillery – Tudor, Pickering & Holt

Okay. And my last question, from a strategic standpoint I guess it was going to follow those six, we started going through this plateauing and recount as well and you guys were disappointed and willing to take rigs off the market to try to preserve instrument pricing. Should we think about that the same way this time around as rig count falls, at least to a point you guys are more willing to sacrifice utilization than price? Is that the right way to think about it?

Mark S. Siegel

I think what we’ve done historically is make a pretty much case by case, rig by rig evaluation of each opportunity to proceed and made a decision kind of on a basis – we kind of make them rig by rig as to whether it’s appropriate to take, maintain the rig operating, potentially at a slightly lower price, or to in effect lay the rig down to in effect try to help maintain price. So that’s a decision we make case by case. I think it’s fair to say that we’re going to try to do both maintain share and maintain price.

Jeff Tillery – Tudor, Pickering & Holt

Okay, thank you very much.

Operator

Your next question comes from the line of Ben Dale (ph 00:33:57) with Bernstein. Please proceed.

[Ben Dale – Bernstein]

Hi guys.

John S. Siegel

Good morning Ben.

[Ben Dale – Bernstein]

Good morning. I have just some questions on where the activity was weakening the most. Can you give us some color on the – which regions you’re seeing the greatest weakness in, how big of a quality spread you’re seeing between high end rigs and low end rigs? And which particular operators are you seeing the large cap PMPs or the privates and microcaps falling away from this market the most?

Douglas J. Wall

Well Ben to start off with, interesting enough as we said, the rig count actually went up in the month of October and it’s only really been the last couple weeks that we’ve seen any sign of weakness at all. And it’s been very spotty. I would hesitate to try and generalize at this point about where it is, what size of rigs. I would say at this point that from what we’ve seen which I don’t think is the same as what some of our competitors have seen, we’ve seen some weakness in east Texas and we’ve seen a little bit of weakness in west Texas.

I think the east Texas piece of it surprised us a little bit because primarily that's the area where the Hayesville is driving a lot of business. In terms of rig sizes, it's been really highly unusual. You might have expected that smaller rigs, less capable rigs, might be the ones being laid down. To date, that's not what we've seen. In our own experience, we've seen some very good quality rigs that people are just saying look, I can't continue my program, I'm going to have to let that rig go.

So I think it's a little too early in the process to really generalize about the type of rigs in some of the markets. To be honest with you, we would have probably expected some different markets to show signs of that weakness first, and so far, those markets have held up very, very well.

[Ben Dale – Bernstein]

Okay. Great. And just on the other side of the equation, obviously steel costs have come down, construction costs appear to be starting to moderate, have you seen any signs that the cost of refurbs on new builds in the rig market are starting to moderate, and if so, by how much? Or, when would you expect to see that if it hasn't already started?

Douglas J. Wall

Well, we've seen steel prices recently sort of dropping in the 15 to 20% range, so think we've seen some of that already. I think they will continue to drop. I don't think it has a huge impact on the costs of new build rigs but it probably could be somewhere in the order of magnitude of a million dollars on some of these rigs, all in. But I don't think it's all washed through the system at this point.

[Ben Dale – Bernstein]

Okay. Thank you very much.

Mark S. Siegel

And I would just add one further thought. So far, in terms of what is being experienced with respect to some customers deciding to curtail their rig programs, I think it's very customer specific and we've seen, as we hope we've indicated both in the press release and in our conference call so far, that our rig count stayed very strong and was in fact advancing through most of October, and we think that maybe different from some of our competitors who may have seen some softness in the count earlier than that related to who their customers are, and that's what we're seeing now. And frankly, we think that we may be slightly advantaged going forward as against some of our customers because of our wider ranging customer base, and what some people have referred to as the checkbook customers, and we have perhaps greater representation of those people for whom credit may be less of an issue.

Ben Dell - Bernstein

Okay. Great. Thank you.

Operator

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

Arun Jayaram - Credit Suisse

Good morning, gentlemen.

Mark S. Siegel

Arun, good to see you.

Arun Jayaram - Credit Suisse

Yes. Good talking to you guys. Real quickly, have you seen any impacts to pricing? You mentioned that you've seen some rigs getting let go in east Texas and west Texas, what are you seeing in terms of pricing?

Douglas J. Wall

To be honest with you, Arun, because the rig count continued to go up in October, we've actually seen our pricing continue to go up somewhat through the month of October. Now, having said that, we are getting some pressure from certain customers, as Mark indicated before, that are trying to get ahead of the game and saying hey, look, I can't drill those wells at that price anymore, can you help? But we really haven't seen any steep discounting to this point, and again it's a case by case base talking to each individual customer about their needs for the next quarter and the rig they're going to need.

Arun Jayaram - Credit Suisse

Fair enough. Second question, Mark, doesn't seem like you're getting much credit for the dividend policy. If I look to some of your peers in the offshore drilling space, Diamond Offshore has a pretty interesting policy where they pay out a dividend based on somewhat of a formula, and tend to get a lot of credit in the marketplace by being a pretty significant dividend payer. Have you thought about looking at a philosophy or strategy that focuses on returning a significant amount of your free cash flow through a dividend policy, given the ying and yang and just the difficulty and short cycle nature of the North American land business. I'd be interested in your thoughts on that.

Mark S. Siegel

Yes. Have given that some thought, and continue to think about it. I feel that what we have done historically where we've invested substantial amounts of capital in our equipment and in new rigs and in upgrading our rig fleet, in our pressure pumping business, as well as substantial dollars spent buying back stock and then the remaining, in effect, free cash flow going to dividend has been a pretty good policy for generating shareholder return long term. Right now, I agree with you 100% that the market isn't giving us much respect for the dividend, but my thought is that right now is sort of a poor time to make judgments about stock prices. My own sense right this minute is that there's a lot of dislocations in the equity markets and you're seeing a number of securities, including ours I think which are wildly mispriced.

My hope is that as the message gets through to shareholders and investors that Patterson is a good strong company with a great balance sheet, no real significant exposure to the current credit issues that are sort of swamping some other places, that in effect over time, people will get the message. You know the old Buffet comment about that short term the markets a popularity contest, and long term it's a weighing mechanism. I have a sort of comfort that long term — the weighing mechanism trumps the popularity contest.

Arun Jayaram - Credit Suisse

Fair enough. And last question, as obviously you've — follow up to Jeff's question is you've added about eight additional rigs in terms of the new built count. Are those — have you ordered the parts for those, or could those be adjusted given the changing market landscape?

Douglas J. Wall

Well, we have placed the orders with National Oilwell for those rigs. I should point out, Arun, that they're scheduled for delivery for national late in the third and fourth quarter of 2009. So, at the moment, we're in line, we have placed the orders. We hope that by that time this market will have corrected itself, and this is part of the long-term strategy for us in terms of upgrading the quality of our fleet. We're very pleased with what we've done in the last couple of years. We think this is just a continuation of that.

Arun Jayaram - Credit Suisse

Okay. Fair. Thanks a lot, guys.

Operator

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

Mike Drickamer - Morgan Keegan

Hey. Good morning, guys. I wanted to follow up on an earlier question where you were talking about your customer base. Can you perhaps characterize how your customer base is? Perhaps what percentage the checkbook customers you were referring to, versus how much were perhaps larger independents that have a little more access to capital?

Douglas J. Wall

I would say about 50% of our customer base is kind of the checkbook driller, and a good chunk of our business would be what I'm going to call kind of the major independents. If there's one area or segment of our customer base that we don't do a lot of work for, it tends to be the majors, the Shells, the Exxon Mobils, the Conoco-Phillips, that ilk of customer. So we have a very strong representation throughout the customer base, but I would say that the majority of it is with the people like DEVINs and the EXCOs and the XTOs, and certainly we mentioned the checkbook drillers before. That is a big part of our business.

Mike Drickamer - Morgan Keegan

Okay. Mark, a question for you; given the liquidity concerns of the market, I know you guys don't have any debt and you have cash, but how much of a priority is stock buybacks here for you?

Mark S. Siegel

You know, that's a question that as a board and management we wrestle with which is there's a lot of competing good uses of capital. We think that rigs that we've been building have situated the company in a very favorable position. We also think that the buyback is obviously, particularly at these prices, is extremely attractive. So those are the things which are the priorities. We also think that paying and maintaining our dividend is another priority. So these are the things that, in effect, management is focused on. To say which one is a higher priority or to give you a specific dollar amount, I really can't say anything more than we have $129 million authorized on the stock buyback that's not yet spent, and we have been consistent purchasers of stock when we think the opportunities are attractive.

Mike Drickamer - Morgan Keegan

Okay. Thanks a lot, guys.

Operator

Your next question comes from the line of Dan Boyd with Goldman Sachs. Please proceed.

Dan Boyd - Goldman Sachs

Hi. Thanks. Of the eight new builds that you ordered this quarter, were any of those backed by customer contracts?

Douglas J. Wall

No. They weren't.

Dan Boyd - Goldman Sachs

Are you — so I'm assuming you ordered them because you are seeing still demand for those types of rigs from customers that are willing to sign contracts?

Douglas J. Wall

Well, we believe that given the delivery schedules — you know, the delivery schedules got pushed out into the latter part of 2009, and we felt with those delivery schedules that we needed to be in line to continue on with our program.

Dan Boyd - Goldman Sachs

Okay. Fair enough.

Douglas J. Wall

I should point out that a couple of years ago, Dan, we ordered 15 rigs and virtually had no commitments for them at that time, so having an additional eight rigs with no commitments presently, we're not uncomfortable with that.

Dan Boyd - Goldman Sachs

Okay. And then going back to the rate versus utilization question; given that you did just spend some CapEx on reactivating a number of rigs, do you think you might favor utilization a little more than you did in the late part of 2007?

Douglas J. Wall

No. I really, like I say, to respond to what Mark said before, we look at each case on a case by case basis and decide — both of those things; market share and price are very important to us, but we've never been a company that is strictly out trying to get market share. We're in business to make money, and you don't pay us for how much market share we have, you pay us for the results, and we have to make that balance between price and share everyday to try and figure out what's best for our shareholders.

Dan Boyd - Goldman Sachs

Okay. Understood. And then of the rigs that you're seeing which the customers are releasing, are any of those in the 1,500 horsepower category? I would assume yes, given that they're in the sort of east Texas area?

Douglas J. Wall

Well, very few of ours, but are you asking specifically about us or what we're —

Dan Boyd - Goldman Sachs

Also just what you're seeing in the industry as well.

Douglas J. Wall

Well, we've actually been a little surprised. We've seen some competitor's 1,500 horsepower rigs come down in certain markets. We've had a couple of ours announce that they will be finished at the end of the current well, but in one of those cases we've already got another well for that rig to drill.

Dan Boyd - Goldman Sachs

Okay. And then one last question; I think you mentioned that you felt like the checkbook E&P companies had better access to capital? Did I hear that correctly that they weren't being impacted by the credit crunch?

Mark S. Siegel

Yes. Basically they drill from cash.

Dan Boyd - Goldman Sachs

Okay. I think we just heard from some of the guys, at least on the —

Mark S. Siegel

Let me say this to you also. I think there's two elements to that. One is that A, they're in effect putting back their cash flow into the ground, and that's the way most of those customers kind of think about their business. In effect, for every dollar I take out, I'll put back a dollar or $0.80 or whatever the number is, but they're putting back, in effect, their royalty checks back into the ground in further drilling. So that's the first point. Second, this is a point that I think is perhaps not maybe as well appreciated; smaller regional banks, particularly banks in west Texas and other places that are very much energy related with strong depositor bases, are in the position to make loans to their customers and are doing so. That's very different from commercial money center banks which are finding themselves in a very different situation —

Dan Boyd - Goldman Sachs

Okay.

Mark S. Siegel

— and I think that the press is about the commercial money center banks, not these smaller local banks in certain markets if that makes some sense.

Dan Boyd - Goldman Sachs

Yes. It does, and I guess the proper way to think about it then is your customer base may see a little bit longer of a delay if commodity prices stay low, then some of the larger E&P companies that are having credit issues, that impacts them today. And if commodity prices rebound, your customers shouldn't see the same downside that others are seeing I guess is the —

Mark S. Siegel

Well, I think that the commodity price affects all customers, the credit issues may affect some customers, is what I think I'm trying to say.

Dan Boyd - Goldman Sachs

Okay. Thank you.

Operator

Your next question comes from the line of Andrew Coleman with UBS. Please proceed.

Andrew Coleman - UBS

Hey. How's it going? Thanks.

Mark S. Siegel

Are you there?

Andrew Coleman - UBS

Yes. Can you hear me?

Mark S. Siegel

Yes.

Douglas J. Wall

Yes. Good morning.

Andrew Coleman - UBS

All right. Sorry. They're just having a fire drill on our floor, so sorry about that. It just started a second ago. Anyways, I had really three questions; the first is kind of looking a bit more on rig substitution. We've heard some operators talk about using low horsepower or so called sputter rigs be it in Appalachia or in parts of east Texas and perhaps Fayetteville to try to save rig costs. Are you seeing that across, or playing a bigger role in any of your other business areas?

Douglas J. Wall

No. We really have not seen that. I know there's been a little bit of that going on. I think some of that was primarily because they couldn’t get a 1000 or a 1,500 horsepower rig, but I really don't think it saves much money. The other interesting thing is that rig costs today are a pretty small proportion of the total cost of getting a well drilled and completed. In fact, we've seen some numbers recently that the cost of casing is actually more than the cost of the actual drilling rig cost. So, to answer your question, we have not seen much of that impact of small rigs coming in and doing sputting work ahead of us.

Andrew Coleman - UBS

Okay. Thank you then. Then the second question then; just looking at your pressure pumping business, do you think that as companies drill less here in the short term that you would expect to see, or are seeing, much of an increase in the amount of I guess work over work or refrac activity as people go back and try to restimulate and keep some of these new horizontal wells flowing?

Douglas J. Wall

Well, I think there's been very few of the horizontal wells fracced and completed at this point, but I think it is interesting, that market up there has always been a market where there's a lot of refracs, there's a lot of ongoing recompletion work, and that's the kind of work that I think actually has slowed down over the last 12 months because people were so focused on the Marcellus and Huron. We're now starting to see some of that traditional work come back into the marketplace because of the slowdown in some of the Marcellus and Huron.

And I should say that we plan on doing our first horizontal fracs in the Marcellus here in the month of November, and up to this point we have not done one of those, but as I said earlier, very few of the horizontal fracs have really been completed to this point.

Andrew Coleman - UBS

Okay. Excellent. And then my last question is a bit more, I guess rolling back the clock a few more years, but looking at what happened in the 2001-2002 kind of recession here in the US, which I don't necessarily think we're in a recession right now, but we'll let the economists debate that, but rig count came back about 40% and of course it snapped back within really a year and a half, I think largely as a result of the fact that production growth was declining in the US. How do you think things will kind of roll forward given that production on the macro level is growing at somewhere between probably 2 and 8% depending on which data set you use, and does that offset some of the industries' discussing 35% percent first year decline rates as being kind of that equalizing factor and put additional pressure on the overall drilling business?

Douglas J. Wall

I think you've asked the $64,000 question which I think a lot of people would love to know the answer for, and I'm kind of reluctant to be someone who tries to answer a question that I think is fundamentally unanswerable, because I don't think anybody really knows. But I guess I have a few observations that I'd like to put on the table.

First is that the notion that because there's been a production increase over the past, say 12 months, and I'm not looking at a chart so I don't have it in front of me exactly what that period has been, but there's been a period of increase. The fact that that occurred doesn't necessarily mean that it will continue and that it's predictably going to happen again in future years. It may well be that that increase came about owing to changes in technology for these horizontal drills, in these shell plays with the stimulation and greater ability to draw the hydrocarbons out of the well, all of which may or may not be continuously improvably such that you'll get continuous increases, so that's the first point.

I mean, the point being that the presumption that the increase will be sustainable and will happen year-over-year, strikes me as one of those questions that I don't know that there's a lot of basis for that assumption.

Second, we do know that the decline rates in these newer wells, particular in the shell plays, are very high, and so it would seem to figure that if in fact drilling does decline in these areas for all the reasons we've been discussing, that there will be a significant falloff in production.

Third, what we don't know is the effect and severity of a decline in overall economic activity on demand for gas, but we do know that gas is principally used for heating and for electricity, and only to a smaller and much lesser extent for production of goods and services, so called industrial uses. Given that fact, and I think the numbers are something on the order of three parts home, heating, and so on and so forth, and one part, in effect, industrial, it would seem to figure that even if there is a slowdown in overall economic activity, that it would not significantly impact gas usage and gas demand, all of which is to say that we're pretty optimistic that if there is a slowdown in drilling, that it will not be a prolonged one.

Andrew Coleman - UBS

Okay. Great. I appreciate your feedback on those.

Operator

Your next question comes from the line of John Dan Yells with Simmons and Company. Please proceed.

John Dan Yells - Simmons and Company

Hey, guys. Just want to touch on customers real quick. Recognizing that a bunch of your customers drill out of cash flow, have you encountered any payment issues yet with the customers? And have you made any, or been requested to make any, changes on credit terms to customers?

Mark S. Siegel

No, John, we haven't. In fact, we watch our receivables very, very closely. In fact, they've actually improved by a day or so over the last quarter. All of our sales people watch the receivables. We're talking to our customers. We have a very thorough credit check policy. We have not, to this point, seen any change in the behavior of our customer base.

John Dan Yells - Simmons and Company

Thanks. That's it for me.

Operator

(Operator's Instructions). Your next question comes from the line of Todd Garman with Peters & Company. Please proceed.

Todd Garman - Peters & Company

Good morning. I just want to come back to the 1,500 horsepower rigs here for a second. Is it your understanding that the 1,500 horsepower rigs are being released because operators no longer have wells for them to drill, or is it because the rigs are being replaced with newer rigs that are coming under contract or that are signed to term contract?

Douglas J. Wall

I think it's likely the former, and it's very customer specific, but we believe it's just because they've run out of wells to drill with that rig in that particular area and aren't prepared to move it to a different area.

Todd Garman - Peters & Company

And is the fact that they might have run out of inventory in those areas, is it due to any permitting issues or is it due to some sort of constraint somewhere along the line whether they can't get pipe or is it just simply that they don't have money to drill them anymore?

Douglas J. Wall

I think it's reduced CapEx or reduced cash flows from those particular fields. It has been very field specific to this point, and I think there's certainly a commodity price issue at play here. There may be some fields, but with $6 and $7 gas, people are not prepared to spend their cash there.

Todd Garman - Peters & Company

Thank you.

Operator

Your next question comes from the line of John Curber with Bennett Management. Please proceed.

John Curber - Bennett Management

Yes. I had to jump off at one point. I'm just wondering if you have kind of given a target for what your CapEx will be in '08 and how it would be spread out over the year. I know it's an uncertain time, but can you talk about guidance on CapEx?

Mark S. Siegel

I assume you're meaning for 2009?

John Curber - Bennett Management

Yes.

Mark S. Siegel

We've said that — in prior calls we had said that we expected approximately $600 million and we've kind of tried to break that down to approximately $80 million of maintenance CapEx for the drilling business, approximately $50 million for the pressure pumping business, and the balance for our refurbishment program and our new rigs. Having said all that, that's been put forward in prior conference calls and we're just repeating it today as being what we've said. We also said — we've covered this, I'm being a little quick about this. We also said that we're in the process of our yearly budget cycle where we do both operating and capital budgets that that would be presented to the board later in the year and finally approved.

Obviously, in light of the current circumstances, we're taking a very hard look at discretionary capital and trying to make a careful judgment as to whether that $600 million ought to be adjusted. And we'll, as we go forward, we expect to be asked that question at the beginning of next year on our conference call and kind of give you an update at that time.

John Curber - Bennett Management

Okay. Thank you.

Operator

And at this time there are no further questions in the queue. I would now like to turn the call back over to management for any closing remarks.

Jeff Lloyd

Thank you. We would like to make a couple of just comments, and I'll turn it over to John Vollmer about some very specific points to perhaps help people in their thinking about our business. John?

John E. Vollmer III

Okay. A couple items we didn't cover on the call. We've said that our estimate for the tax rate in the fourth quarter would be an effective rate of about 35.8%. The rate was slightly lower in the third quarter. We got a little bit of benefit from true up to our prior year tax return when we filed it.

Another, in terms of the pressure pumping business, activity continues to be strong in our Appalachian pressure pumping business, but I'd like to remind people that in the fourth quarter, we do see typically a seasonal decline as a result of less daylight hours and less workdays due to the way Appalachia specifically deals with the Thanksgiving holiday and the Christmas holiday. So, our guess is that sequentially we have a seasonal decline of about 5% revenue versus the third quarter. However, we think the margins will stay very similar on a percentage basis at somewhere around 40%.

The fluids business is a little bit difficult to understand the third quarter, given the impact of the hurricane, and our guess there is that sequentially, revenue will be off about 5%, but that on a margin basis it will become a little more like the last first quarter at somewhere in the 12 to 13% range. Included in the third quarter numbers for fluids was a $650,000 charge related to damage that occurred to our facilities.

Lastly, on the E&P segment, we benefited, like other E&P companies from great commodity prices earlier in this year. With the decline in those prices, we would expect we'll be down probably 20%, somewhere in the $11 million or so range in revenue, but that our costs of that revenue will drop back down towards somewhere in the 25% range. And that was it.

Jeff Lloyd

Thanks, John. I'd like to thank all of the participants in today's call for being on our call and to look forward to our next call in February. Thanks, everybody.

Operator

Thank you for joining today's conference. That concludes the presentation. You may now disconnect, and have a great day.

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Source: Patterson-UTI Energy, Inc. Q3 2008 Earnings Conference Call
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