Patterson-UTI Energy Inc (PTEN) 2002 Q3 法說會逐字稿

Good morning, ladies and gentlemen. And welcome to the Patterson-UTI Energy third quarter earnings conference call. At this time, all participants are in a listen-only mode. Following today’s presentation instructions will be given for the question-and-answer session. If anyone needs assistance at anytime during the conference please press the star, followed by the zero. As a reminder, this conference is being recorded on Tuesday, October 22nd of 2002.

I would now like to turn the conference over Mr. Jack Lloyd. Please go ahead, sir.

Good morning. On behalf of Patterson-UTI Energy I would like to welcome you to today’s conference call to discuss the results of the third quarter ended September 30, 2002. Participating on the call will be Mark Siegel, Chairman, Cloyce Talbott, Chief Executive Officer, Glenn Patterson, President and Chief Operating Officer, Jody Nelson, Chief Financial Officer, and John Volmer, Senior Vice President, Corporate Development.

Just a quick reminder that statements made in this conference call which state the Company’s or Management’s intentions, beliefs, expectations, or predictions for the future are forward-looking statements. It’s important to note that actual results could differ materially from those discussed in such forward-looking statements. Important factors that could cause actual results to differ materially include but are not limited to declines in oil and natural gas prices that could adversely affect demand for the Company’s services and their associated affect on day rates, rig utilization plan and capital expenditures, adverse industry conditions, difficulty in integrating acquisitions, demand for oil and natural gas, and ability to retain management and field personnel.

Additional information concerning factors that could cause actual results to differ materially from those in the forward-looking statements is contained from time to time in the Company’s SEC filings, including but not limited to a report on Form 10-K for the year ended December 31, 2001, and Form 10-Q for the 2002 reporting periods. Copies of these filings may be obtained by contacting the Company or the SEC.

And now, I’ll turn the call over to Mark Siegel for some opening remarks, to be followed by questions-and-answers. Mark.

Thanks, Jeff.

At the beginning, let me welcome everyone to our conference call today as we announce third quarter results. With me are Cloyce Talbott, the Company’s CEO, Glenn Patterson, the Company’s President and Chief Operating Officer, Jody Nelson, the Company’s Chief Financial Officer, and John Volmer, Senior Vice President, Corporate Development.

I assume by now that everybody has had a chance to look over our press release, so I’m just going to highlight some of the very biggest points. Today we announced as the second largest operator of land-based oil and natural gas drilling rigs in North America our results for the three and nine months ended September 30, 2002. We reported net income of $249,000, zero cents per share for the quarter, compared to net income of 60.4 million or 77 cents per share for the three months ended September 30, 2001.

Revenue for the quarter was 133.5 million versus 289.1 million for the comparable three months in 2001. Net income for the period was $339,000, or again, zero cents per share, compared to net income of 145 million or $1.84 per share for the nine months ended September 30th, 2001. Revenue for the nine months was 387.1 million versus 815.3 million for the comparable nine months in 2001.

As Cloyce Talbott said in the release, ‘our average total rigs operating during the quarter improved slightly to 127 from 119 in the previous quarter despite the absence of the seasonal increase in drilling activity in Canada that we would normally experience in the third quarter. Although we averaged only four rigs operating in Canada for both the second and third quarters we are optimistic that all 16 of our Canadian rigs will work during the winter drilling season. For the week ended October 18th, our most recent period of information, we averaged 141 rigs working, including 137 in the U.S. and four rigs in Canada.

In the third quarter we continued our policy of maintaining our most experienced field personnel and refurbishing our equipment during this relatively slow period. While this practice continued to have a negative impact on our costs we are prepared to respond quickly as industry conditions improve.’

Mr. Talbott added that ‘the drilling and completion fluids businesses was up slightly compared to the prior quarter because of increased activity in the Gulf of Mexico, and that the pressure pumping revenues were up in the second quarter reflecting typical seasonal increases.’

As I said, the relative stability in drilling activity that began in May continued through most of the third quarter. However, in the latter part of the third quarter we began to see a gradual increase in rig utilization, and continue to believe that significantly increased drilling will ultimately be necessary to offset the reported decreases in natural gas production arising from depletion.

We continue to maintain our strong balance sheet with no long-term debt, 146.2 million in working capital, and 63.6 million in available cash, providing us with substantial financial flexibility.

Stepping away from our press release this morning, let me give you a little color and a little additional information. At the start of the third quarter we had 118 rigs running. That was 114 in the U.S. and four in Canada. At the end of the third quarter we had 132 running, of which two were in Canada. That’s, of course, the 100, gives us the 127 average that we discussed before. Currently, 141 rigs running, of which four are in Canada, so 137 in the U.S. and four Canadian.

The up-tick in activity which is mentioned in Cloyce’s quote is consistent with our prior comments. In our report for the second quarter which we put-out on July 18th we said ‘we expect the current activity level to continue throughout the summer months until the affects of declining supply becomes – until the affects of the declining supply becomes evermore apparent as we approach the winter months.’ And, indeed, that’s just what occurred. As we started to get closer to winter we saw the up-tick in activity.

For the rest of this quarter our expectations are the following. We have seen a pick-up in U.S. activity. We expect to see a pick-up in Canadian activity. However, we don’t expect to see the Canadian fleet really to be operating in large quantities until around the first week in December. For the rest of the quarter we kind of think that we’re going to see the addition of about a rig per week. We expect an average of eight rigs total – pardon me – we expect an average of eight rigs operating in Canada for the quarter. So that’s gives us an expectation of 145 or so rigs operating for the quarter on average.

As for margins, we’re not expecting to see significant changes. We do not foresee significant changes in rates in the fourth quarter. By rates I’m speaking of average revenue per operating day. We expect that will occur when utilization exceeds 50 percent. And just as a benchmark that’s about 154 rigs in the U.S. We would expect to reach that level, that over 50 percent, when the majors and the mini majors return to work with new capital budgets.

Likewise, as rates are expected to be consistent we also expect our posture to remain at approximately the same level, as well. Of course, the comments about margins and rates depends upon our competitors not attempting to change market shares by lowering prices significantly. In terms of our smaller subsidiary businesses our pressure pumping business for example, we expect that third quarter performance will carry-forward into the fourth quarter with modest downward adjustments typical of the fourth quarter due to holiday intervention and activity levels, that’s for Thanksgiving and Christmas obviously.

As for the mud business the same, it’s the same basic comment, we have an expectation of approximately the third quarter, but in this case there’s a more significant downward adjustment because of the two weeks lost due to hurricanes in the Gulf and to a lesser extent for the Christmas holidays.

With that, we’d like to turn it over to questions from our participants.

Thank you, sir. (Caller Instructions.)

Our first question comes from Jim Rollyson with Raymond James. Please go ahead with your question.

Good morning, guys.

Hi, Jim.

Hi, Jim.

Mark, you talked about Q4, you know you’re – it sounds like your rates and margins are more or less going to be flat. What are you seeing from the competitive landscape? You mentioned some of your competitors trying to take market share, and obviously, you know with a flat to slightly increasing rig count your rates came down a little bit. Is that a function of some guys out there that are still cutting price to a degree?

To some extent, Jim. What I was saying really was that I expect that our rates will stay about this level until we get to that over 50 percent utilization. But the confidence that they stay at about this level depends, of course, on somebody not trying to significantly increase market share. It’s more a prospective comment than a perspective comment.

Sure. And obviously, as you start putting rigs back to work, which it looks like you started doing based on your quarterly release, when do you expect your daily cost per rig to start coming down meaningfully?

Well, there’s kind of a number of factors at work, Jim, and kind of what we were trying to give you in my mind is the sort of, is the upshot of a number of factors, many of which are operating in different directions. On the one hand we’ve maintained some expensive personnel and carried them forward, and we will be spreading those personnel over a larger number of rigs. So that’s one that helps us as the time passes. By the same token, as you all know, we put forward a 10 percent decrease in wages at the beginning of the year, and have carried that forward through this quarter. We wouldn’t be surprised if we started to see a continued up-tick in activity, that’s there some pressure on wages. So that goes the opposite direction. And then last, there’s always startup costs when you put rigs to work, and so there’s that point. In the totality we think that expenses stay relatively flat, and we expect revenue stays relatively flat. But those are the factors that we were trying to balance in making that, taking that look forward.

Sure. And have you spent much time, I guess probably Cloyce, or even Glenn, talking to your customers about why given the environment we’re in with where commodity prices are and where their rates are, certainly why they’re not spending more money so far this year?

Let me turn that over to Cloyce.

Jim, you know, this is my theory of what’s happening in the industry. And you know, we do 60 percent of our work for the small independents, the ones that you wouldn’t recognize their name. We do about 34 percent of our business for the mini majors, as Mark calls them, and that’s the larger independents that are not integrated companies, and we do six percent of our work for the majors.

Now back to why I think that we’re not working, and with these high commodity prices you would think that we’d have all of our rigs running with $4 gas and $30 oil. But what we’re seeing happen with our little independents is that, that we work for is they sell-off a lot of their deals, and we’re seeing so many people call-in and need to sell part of their deals. And my theory on that is that when these guys sell-off their deals they sell them off to the high net worth individuals in the U.S. And a lot of those high net worth individuals don’t consider them high net worth individuals anymore because of the stock market, particularly, and the economy in general. So they’re having a difficult time selling those deals.

And there’s another factor to it is that they’ve had pressure on them because of gas–on-gas competition. You know, we have this antiquated pricing system for natural gas, when you think storage is going to fill, gas price again is going to go down. And the type of wells that we’re drilling now, and has the high decline rates, these small independents try to guess what the gas price is going to be.

And so I think all those factors lead us to the fact that when they have confidence that the price of gas is going to be higher, and now we’re approaching the end of the year, and these high net worth individuals that normally are buying the deals are going to realize that they’re probably going to pay some taxes anyway, and I think that you’re going to see the work start to pick-up from that standpoint.

All right. And then just lastly, with pricing staying relatively flat and the rig count staying relatively flat, are you seeing any changes that is driving anybody to – on the rig acquisition side that might show-up now, that hasn’t been previous?

No. Frankly, Jim, the conversations that we’ve been having towards further acquisitions, and there are always ongoing conversations and there have always been ongoing conversations, I don’t think it changed one iota from …

Six months ago.

Say the beginning of the year to this point. John?

I agree.

I agree, too. The people are still in the contract drilling business are fairly well off financially, and the ones that are out there don’t have financial problems and they can pick the time they want to sell, or if they do want to sell.

Thanks, guys.

Your next question comes from James Wicklund of Banc of America Securities. Please go ahead with your question.

Good morning, gentlemen.

Hey, Jim.

Mark, if I worked the math out then you’ll have, you’ll finish the quarter with about 163 rigs running? Does that sound about right?

Jim, you know we never would comment on your arithmetic, but.

You know, it’s pretty simple. I’ve got an abacus here, and I’m working it hard!

You know, Jim, your credit is just about is as good as ours!

I mean you’re going from the end of the quarter at 132 to finishing the year at 163, not that our rig count forecast is accurate. But that would imply that you’re taking some significant share yourself in terms of the market going from about 14 percent of total rigs running to like 17, 18 percent. If, if ….

It depends on what rig count is at the end of the year.

No, no. Like I say, we’re looking at about 900 for total rig count, and off shore staying flat. So.

Jim, in looking at those numbers, be careful when you put Canada and the U.S. together to get your, you know, 160ish number. I think you’ve’ got about 15 or 16 working in Canada. I think we indicated in our comments that we thought things were going to get busy in the winter drilling season in Canada, which, you know, I think we believe that’s true for the other Canadian people, too. But for looking at market share I think you have to back-out the Canadian and you’d be – well, would that get you on your math about 145 or so?

Yeah.

Jim, I don’t think that in our thinking there was any expectation of changing, any changes in market share.

Okay.

But no, let me say categorically the answer to that was not an expectation of changing share. It is exactly what we said in my comments, that we thought we’d have the Canadian fleet fairly highly utilized by the end of the year.

Okay. Now your margins came down in the quarter, and you’re the like the first [land] to report, and so we’re going to assume that everybody did. You have traditionally led rates down, you usually lead them up. Is it public companies or is it private companies, or just general malaise in the market pushing margins down? Because if you’ve gone from 118 rigs at the start of the third quarter to 141 today usually you would expect to see day rates move-up in a higher utilization market?

We still think there’s a high enough utilization market to see that yet, Jim. This is Cloyce. We’ve never seen day rates increase at this level of utilization. In fact, in the last upturn we saw day rates increasing between 50 and 60 percent utilization, and that was a first.

But Cloyce, shouldn’t they at least stay flat with utilization going up?

Jim, you have the roll-off of contracts that were at higher rates, that have some impact on us, we expect probably a higher impact on maybe others, but we have some impact of that. But remember, we’re under 40 percent.

Yeah.

In the quarter. I mean you can say that you go up, but you go up from a pretty low number. You’re not expecting too much activity change.

Okay. A lot of service companies are talking about cycle-over-cycle. They’re growing their earnings power. You guys have obviously made acquisitions in the past, and you all will probably make them in the future. In terms of your other businesses, pressure pumping, the fluids business, in percentage terms do you have any idea as to who might get more capital over the next year, rigs or the other two?

In percentage terms?

Yeah, I mean, you know, which business would you grow faster? I know which one is bigger.

I – you want me to take a shot at that one?

Go ahead, Cloyce.

I think that we have more opportunities in pressure pumping to deploy capital, and put capital to work than we do in the other businesses other than drilling. We could deploy a lot of capital in drilling if we could find someone to buy.

Right. Well, that was my question, Cloyce. I appreciate it.

And between – drilling and pressure pumping are the two places in which capital is going into. In my own mind in pressure pumping we have funded some internal expansion as opposed to acquisitions, and we expect we’ll continue to do so. That business has grown, you know, very nicely over the past six years. You could pick whatever period you want. You know, it’s interesting, operating income reached a level of revenue from that – during that period of time. So I think there’s some key opportunities there, but on the other hand, to the extent which we find good acquisition opportunities in the drilling side, those that historically power the growth of the businesses, so we’d certainly take advantage of them.

And we certainly would not turn-down an opportunity on the fluid side. I’d just – we just have not found anything recently that we thought would improve our position in the fluids business, but we’re certainly in the position to do that if something does present itself.

Cloyce, appreciate it, that was my question. Thanks, gentlemen.

Our next question comes from Kurt Hallead from RBC. Please go ahead with your question.

Yes. Good morning.

Hi, Kurt.

The question is I want to get a sense from you guys if you think that there’s going to be any kind of change in the spending patterns with respect to geographic markets within the U.S.? So do you get a sense that maybe some capital may be shifted from say South Texas or the Gulf Coast area, to the Rockies next year when this pipeline is completed in Wyoming? And if so, what kind of benefit do you see for your business?

You know, there’s been talk about that going on for so long that it remains one of the consistent conversation topics in the industry. You know, we’ve considered it, and have the ability to move rigs into the Rockies quickly to the extent to which demand were to increase in the Rockies, and would expect we would do so. At this point, it’s one of those nice conversation topics, but it hasn’t become a real significant event as yet.

All right, so the pipeline is scheduled to be complete next May which should basically narrow this price spread between Rockies gas and what you get in the hub, which would spur additional drilling activity in the Rockies. And it’s coming close to fruition, but you haven’t quite seen any indication of that just yet from your customer base.

We’re hearing the conversations I suspect you’re hearing, but we haven’t seen the activity level reflect it yet.

Now from a pricing standpoint would it be fair to say that margins and pricing in general from an industry perspective have stabilized now that the, sort of the industry shake, market share game has ended, or something along those lines? Would you say that pricing is stabilized here?

Yeah, I would say it’s stabilized. We have said at the end of our – in our earnings release for second quarter we expected basically pretty stable margins in third quarter which is what took place. Pretty stable business environment, which is what took place. We said that we expected that at the end of the third quarter there’d be an up-tick as winter approached, and that’s what occurred. And we haven’t yet seen any impact commensurately with day rates or margins, and we’re not really expecting that until we get to this kind of above 50 percent utilization.

Okay, so there’s no great market share wars taking place from what you can tell?

Not of which we’re aware.

I don’t really think that there’s that much. There’s always when there’s less than 50 percent utilization, and I used to say less than 70 or 80, but now I think it might be a little lower number, that there’s some pressure on pricing. But it’s been fairly stable for us, wouldn’t you say Glenn for this whole last quarter. It’s just been kind of floating along.

Now, I just want to make sure that I understood something correctly. You’re currently running 137 rigs in the U.S., is that correct?

That’s the average for last week.

Yeah, the average last week.

And you don’t anticipate that that’s going to change between now and year-end? Did I hear that correctly?

No.

No, you didn’t hear that correctly. We threw out the concept that we had a regular week in the U.S., you know, and then run the majority of our fleet in Canada during the month of December. That would give us an average for the quarter of somewhere between 145 and 150 rigs.

145 for the U.S.?

No, that was total.

Right, well that is what I was saying. So if you’re running 130 – I’ll talk to you offline with the specific semantics on that. I don’t want to waste time on the call with that.

Okay, now in general, the last question here, do you get a sense that, you know, in terms of inquiry levels, have they accelerated? Have they flattened out? You know, anything along those lines?

We’ll have Glenn Patterson respond to that.

Actually, we’re seeing quite a few more inquiries, and a lot more possibilities of getting jobs. But it’s, again, I guess it’s been probably an influx of about 10 a week.

Okay. Would you say that your customers have plenty of prospects but no capital flow-down from the executive level, or are they prospect short?

Kurt, this is Cloyce. I, you know, when you start to ask about prospects I think you’ve got to put commodity prices attached to that number. And you know, my theory always has been there’s a lot more prospects at $3 than there is at $2.50, and there’s more at $3.50 than there is at $3, and there’s more at $4 than there is at $3.50. And I think you‘ve got to get the customers thinking that the commodity price is going to be stable. And if you have a $4 commodity price stable and they think it’s going to be stable through 2003 and maybe 2004 you’re going to have a lot of prospects to drill.

And I always refer to the Southeast New Mexico, where we play the [Tokomora] trend. They pretty much know on average what those wells are going to make from a, you know, from a cumulative production standpoint. And so it’s tied to the cost and the commodity prices that they’re projecting. And so you’ve got to tell us what commodity price you want to say we’re going to have to say when the prospects are available. Now, there might be a limited number of deep exploration prospects, but I think most of our drilling is done in trends like Southeast New Mexico where there’s lots of prospects to drill.

And would you say that on land we were – would you say that we were less likely to see a shift in spending for deeper prospects greater than 15,000 feet than we are seeing on offshore right now, because you had this big shift in capital that’s going into this deep gas plant on the shelf?

I think that that’d be more so in the Gulf than what I’ve seen on land.

So you don’t think the average depths of well on land is really going to change all that much?

I think the average depth on land if the commodity price, the gas price stays above $4 will become shallower. It’s always been that way. The higher the commodity price, the shallower the average well drilled in the U.S. has been.

Okay. Thanks a lot guys.

Than 2001.

Yeah.

Okay. Thanks a lot.

Our next question comes from Neal McAfee with Morgan, Keegan. Please go ahead with your question.

Hi, good morning, guys.

Hi, Neal.

I mean I don’t want to belabor this, but Cloyce, or Mark, or anybody, you know, $4 gas, I mean the [strip] is above $4, so if people, you know, if there’s guys out there that really have a lot of prospects at $4 why wouldn’t they be out there, you know, [indiscernible] and sell in the strip and getting after it? I mean what do you think about the theory that maybe instead of, you know, $2, $2.50 being sort of the low end of what you need maybe that break-even point, because prospects were getting harder and harder to find at $3.50, $4?

I think it’s our customer mix more than it is – most – as I said awhile ago, 60 percent of our business is done in the – and I hate to say mom-and-pop, but it’s the smaller independents.

Right.

And those people just don’t tend to hedge. They take what they get today – I’ve lived out there in that environment all my life, Neal, and that’s just the way they do.

You know, Neal, let me just add this. That we’ve gone from a low point in March of 90 rigs to 137 now. That’s in October. That’s a pretty significant change which suggests to me that there are prospects. This is against a backdrop of over three in storage as an expectation and a concern about completely filling storage. And so, given that backdrop and that uncertainty about gas-on-gas competition which in my mind was very, very, very real until say three to four weeks ago and is still, you know, there as a smaller factor, we’ve had a big increase in activity against a high level of storage. I don’t think that’s – that says as much about prospects as it does about the amount of gas that’s been perceived of as in the marketplace.

No, and I guess [indiscernible] comment to me is – I mean I’ve been following you guys a long time, and to hear you say you think rates will start to move at [60] percent utilization, I mean I remember days when you could be at 70 percent utilization and rates would move. I mean is that, you think that’s a consolidation issue, or are oil companies finally beginning to realize that they need to pay you guys a fair return on capital?

I think there’s a couple of things, Neal. One is that we’ve talked from time to time about the fact that our land drilling industry doesn’t reach the same low levels of cash cost that maybe it used to reach. And maybe it’s true in some of the off shore markets. So we don’t necessarily go to as low a low as we used to go to. That’s point one. Point two is that I think that the perception of scarcity of rigs has finally become a part of the discussion among our customers. I mean it used to be that there was a perception that there were plenty of rigs and plenty of surplus rigs. And it was only in affect in 2001 where it became the concept of scarcity in rigs finally became part of it. So in my mind, it’s starting from a higher low. It’s the perception that there’s really not that many available land rigs, and if we go from 40 to 50 or 60 percent utilization we’re in affect using up a lot of the spare capacity of rigs. And then third, your comment is true that ‘yes’ there is greater consolidation in the industry today than there was before. But I think the factors one and two are also a big part as is three.

Neal I think that what has happened, along with what Mark is saying, is that and in what you said about 70 percent, I’d never seen it until we came out of the ’99, ’98 and ’99 drop in the cycle. And then we started back-up. And I was shocked to see our rates increase, you know, less than 60 percent utilization. And my thoughts are is it’s probably the effective utilization is probably nearly, you know, 80 percent because of the consolidation. We have no incentive to go put rigs out at low rates if we don’t have a lot of jobs, particularly why would we go put a rig out and crew it up and cost us money to go and, you know, drill a well, and break-even, or make very little money on it. It’s just there’s no incentive there. And I think that’s what we’re seeing.

Right. Right, and then I’d just ask Glenn, you said you had 10 inquiries a week now. I mean is that up or has that been pretty constant throughout the summer?

No, I said it’s probably increasing at about 10 a week. We’re getting lots of inquiries. And that’s just a guess but I would say it’s probably increasing. It seems like we have that many more every week.

On a base, I mean how many inquiries do you get a week?

I couldn’t tell you that. I just know we’ve been – we’re getting more inquiries every week.

Another couple of days. Okay. Thanks, Glenn.

Our next question comes from Roger Reese with Simmons & Company. Please go ahead with your question.

Good morning, gentlemen. I promise not to ask anything about prospect constraints here. First question, looking at Canada your expectation is to see a little bit of increase in December followed by a very robust first quarter. What is that based on at this point for you? And where do you see margins relative to say now and relative to the first quarter last year there?

Let me give you kind of a couple part answer, Roger, to that question. We are basing the expectation of the fleet being significantly utilized by the first week in December, based on customer inquiries that we’re getting in Canada. So that’ a basic, you know, the comment is customers in affect trying to tie-up our rigs over this winter season. And that’s the reason for that comment.

The second thought in respect of rates is that those rates are expected to be at least as favorable as U.S. rates, if not more favorable. And as compared to, I don’t actually recall what you asked the question, as to the comparative quarters, and so I’ll let John – throw that one to John. Or please repeat that last part of the question?

Just essentially how the rates would – or the margins would compare to today and then how they would compare to first quarter a year ago?

Compared to today for Canada they’d be a bit higher. That’s a seasonal point, in affect you’re renting more equipment, camps, et cetera, and that we believe would, you know, take our rates up from what we saw during the summer and the fall. Compared to a year ago I don’t think we have full clarity on that yet, probably down a bit, though.

Okay. Looking at the U.S. in the first quarter, it sounds like you foresee some amount of increase in activity about that point. How do you see the first quarter at this point shaping up in the U.S.?

You know, our crystal ball is, you know, a little fuzzy for first quarter. It seems to us that we have seen this move from 90 to 137 rigs. As we said before in the call we’re fairly confident that the trend continues in fourth quarter with, you know, a further increase in utilization. What we have not been able to do is really sharpen the focus enough to say, you know, how long that trend can be used, and to what strength.

Okay. The last question for me, and we’ve got one other to follow-up on. Capex, you made the comment in the press release that you’re looking to take advantage of a lull here to improve your rig fleet. Capex is up year-over-year, and at a time when overall activity is lower. How many rigs are you working on? And what does this mean in terms of rig capacity for you and rig capability? And is there any impact in adding capacity on kind of what that 50 percent utilization level is, that would see pricing move higher?

You know, Roger, I think what we’ve said in prior calls, and which we’ve remained, has remained the story throughout this year for us has been that in a period in which our fleet has not been fully utilized, it was for us an opportunity to work on some of the rigs which needed some, that had some deferred maintenance owing to the fact that they had been run flat-out in 2001, and we certainly didn’t want to shut a rig down in order to, you know work on the draw-works, or the derrick, or whatever. At this point, mud [pads], or whatever. So what we’ve done at this point is do a significant amount of working on those rigs to make sure that the entire fleet is in a ready to go-to-work basis. And that’s kind of one of the highlights of the, you know, operational strengths of the Patterson-UTI Management, I think is that we use the downtime in the industry to get our rigs in a really good shape, so that as the business picks-up we’re ready to quickly put rigs to work.

It was more maintenance capital expenditures other than the drill pipe that we bought, capital expenditures to put rigs back in service. We actually didn’t put any rigs back in service during that time, Roger. It was all maintenance cap expenditures and drill pipe is what we bought.

Okay.

Hey, Mark, this is Scott Gill with Simmons. Just a quick question I had, a comment was made earlier that, you know, the sellers in terms of acquisitions aren’t at any real hurry to sell, given their much stronger balance sheets, et cetera. I was wondering if you wouldn’t mind commenting a little bit on your investment in TMBR/Sharp drilling? What your intent there is? And I believe there’s some options to purchase more shares that come available somewhere later this month. Can you just comment on those items, please?

Sure. We’ve said all along that we found the TMBR/Sharp opportunity to be one of those situations in which there was a seller of a significant block of stock. It was the heirs of Joe Roper. We have always been interested in the possibility of an acquisition if it was available on attractive terms, of that company. When these shares became available we decided that it would be a good opportunity for us to take advantage of it. And we – I think the story has not changed one iota since we made the acquisition, and since we first announced it. In terms of the option shares, I think it’s our expectation that that option will, in fact, be used to acquire the extra shares that are subject to the option. And that’s pretty much the name of that story.

Okay, Mark, before we go on, the option shares just for clarification here, we would have been happy to buy those when we bought the other shares. The sellers for their own planning and tax purposes are the ones who pushed the date out to the later date, so there’s no magical message in my mind in the options. We would have done it in June.

Okay, can you give the start price of those options?

Same as the other shares.

Okay.

They can put them to us, and we can call them from that, all at the same price.

Okay, thank you.

One final question is given your ability to build cash during the downturn, how much longer do you continue to build cash, and you’re obviously limited on acquisitions, but what do you do?

The short answer to that question is that we see cash as an opportunity for us to find good acquisitions. To the extent which we’re unable to deploy the cash in a good acquisition we’ll buy-back our own stock if that becomes the best acquisition that we can do. Historically over many years the acquisitions that we’ve done with our cash has been extremely beneficial to the company. And so we remain convinced as of right now that we’d be better able to use that cash through the acquisition of additional rigs or additional capability of the pressure pumping business. And don’t see that as of this minute it’s better for us to deploy that cash in some other way. We are flexible about that. It is a subject that Executive Management discusses very regularly, and with our Board likewise on a very regular basis.

Okay, thank you.

Our next question comes from Jeff Bailey with Jefferies & Company. Please go ahead with your question.

Yeah, hi. This is Magnus Fyhr with Jefferies. Just a – most of my questions have been answered, but just a question on asset values out there for the rigs. Maybe Cloyce can answer this, have you been out kicking tires here recently. Have you seen any changes in the asset values, or are there opportunities for you guys to buy single rigs? And it doesn’t make sense for you guys to look at single rigs? Or is it going to be more fleet acquisitions going forward?

Well, we’d certainly look at a single acquisition if the price was right, Magnus. But to answer your question, I think that the price has been fairly stable in what we’ve been looking at now for a year, year and a half now? Is that what you’d say, John?

Yes.

And we’re not seeing much movement, you know, up or down.

Right.

But we’d certainly – we would look at the single rigs, or two rigs, or three rigs, or four rigs, or five rigs. And you know, if you could make 10 acquisitions of five rigs, that 50 rigs, so we look at them all the time, Magnus.

All right. That’s all I had.

Our next question comes from Angie Sedita with Lehman Brothers. Please go ahead with your question.

Thanks. Hi, guys. A question for you, you had the increase in the rig count from 118 to 141. And obviously, here now, it’s reflecting your customer base, you primarily work for the small independents. Is that who you’re seeing come back to work here? Is the very small independents, the mom-and-pops?

I think that that’s a lot of it. We are, you know, we pick-up a rig – I think we had one rig for Exxon, and some of the larger independents, whereas adding some rigs. But overall I think it’s more in that 60 percent I said that you wouldn’t recognize their names, that we work for.

My gut having looked at a little bit is it’s pretty consistent with our customer fleet. I mean I don’t think that the pick-up has been in any way disproportionate on one side or the other.

All right. What area are you seeing these gains predominantly?

We talked about that earlier among ourselves. It’s all over. I mean we can’t pick-out one area that’s more dominant than another area. It’s all the same, Angie.

All right. Finally, is there any area that you do continue to [indiscernible] contain, and have you seen any change in their strategy, or expect to see any change in their strategy?

I don’t think we’ve seen any change in their strategy yet. I mean it’s probably too soon to tell, but I don’t expect to see anything different really.

Okay, great. That’s all I had.

Our next question comes from Alan [Laus] with Merrill Lynch. Please go ahead with your question.

Good morning, I just have a couple – well, actually just one now, kind of a clarifying question I guess. It sounds like you’re saying on the pricing side that contracts are rolling over flat, and I just want to know if that would be a fair characterization?

Yes, that’s fair.

That’s all I’ve got. Everything else I wanted to ask you has been answered. Thank you.

Thank you.

Our next question comes from [Amine Pennelly] with John Hancock Advisors. Please go ahead with your question.

Yes, hi. Good morning.

Good morning.

My questions actually have been answered. But just one, perhaps somebody could comment on your non-drilling assets have had really good performance. I’m wondering if you could explain that, in an environment where activity has been very flat?

The pressure pumping business tends to continue kind of in the year following a decline in the drilling business, and so in effect, if you take a look backward at ’98, ’99, you’ll see that while the drilling business had in effect rolled-over you will see that, for example, the pressure pumping business had a good year in the subsequent year. And that’s in effect what’s happening right now is as the drilling activity declined pressure pumping continued its strong performance in effect for the follow-up year. So that’s predictable in that sense.

In our fluids business, in that area I think we’ve made some progress in terms of rearranging the management and doing some other things, and the activity level in the Gulf has picked-up a little bit. And so we’re seeing kind of two benefits there which is a better, I think, execution and a little more activity. And so, in those two areas being in effect, the mud business and the pressure pumping business, we’ve seen slightly better performance. I hope that’s an answer to your question.

Yes. So then you would expect similar performance in the fourth quarter in terms of number of jobs and …

Yeah, we tried to comment on that a little bit. I mean in the pressure pumping business we’re impacted somewhat by our customers not necessarily wanting to work the week of Christmas, and maybe to take a day or two off during the Thanksgiving week which has been some historical impact on fourth quarter activity, as a usual matter in pressure pumping. And we expect the same thing to occur here. Again, in the mud business, fluid business, we’ve been impacted already by the two weeks of hurricanes that occurred in the Gulf. And that has taken away, you know, out of the quarter already a little bit of the activity that we would have expected.

Well, thank you. It’s been very helpful, thanks.

Sure.

Our next question comes from Matt [Conlan] with Liedeman Company. Please go ahead with your question.

Good morning, gentlemen. Good to talk to you again.

Hi, Matt.

Hi, Matt.

Hey, I have a question. When you say that you’re refurbishing rigs, continuing to do that through the downturn, are you refurbishing rigs that worked during the last cycle, or are you actively increasing the marketable capacity of your fleet for the next cycle.

Cloyce Talbott (?): We’re just repairing the rigs that had been working, Matt. We haven’t rebuilt a rig that we bought, for example, that hadn’t been rigged-up to drill. Like the olden rigs, for example, we just have them in our inventory, and we haven’t spent any money on them at all. All the rigs that Glenn has been working on are rigs that were worked in the last cycle.

Okay. So of the 324 rig owned, which I guess is 308 in the U.S., how many of those are workable today? You know, if utilization were there for them?

Yeah, we worked, of the rigs that we own today, 287 of them. That’s combined U.S. and Canada, and 16 of the 287 would be Canadian rigs worked in 2001. And Glenn and his people stack those rigs, you know, ready to run again, and as mentioned before did refurbishing on those. So we would expect that the demand was there, and if we had the crews, that we could run the 287. Additionally, the Oden Rig that Cloyce mentioned were purchased with not a lot to do to make them run. So we could pretty quickly get to 292, we think.

Okay. Terrific. Thanks a lot.

Thank you.

Our next question comes from Joe Agular with Johnson Rice. Please go ahead with your question.

Good morning. Do any of your customers care anymore about drilling for oil?

Glenn Patterson (?): Well, we have several customers that are drilling for oil, but the majority of them are drilling for gas.

I mean is there – I guess what I’m asking is obviously we all see the record low kind of rig count, almost for oil, and I mean if there’s any hope whatsoever of anybody drilling for oil, you know, even the small increases actually could be helped incrementally for tightening up the market. I’m just wondering if you saw any inquiries whatsoever on that front?

There is some. We have some, particularly in-field drilling and for the flooding, you know, secondary and tersorary floods. We have three rigs down in one field, and all we’re doing is drilling in-field oil wells.

Right.

But we – and then that’s picked-up. We had one working there and they’ve added two more, two additional rigs. So we have three in that one field. And that’s occurring some. As far as out exploring for oil, we do drill some, particularly on [indiscernible] seismic prospects we do drill some for oil. But the preponderance of them are for gas. And amazingly there’s a lot of gas wells that have quite a bit of oil with it, so it sure helps the pay-out on that, too.

Right, okay. Well, I was just wondering, I mean it’s, you know, the one thing that is remarkable is just how low the rig count has gotten on oil then. Maybe it’s just something that’s not going to change, but again even putting 60 rigs back to work might make a difference. It still would be really, you know, below 200 or so. So, thanks a lot.

Thank you.

Our next question, a follow-up from Kurt Hallead with RBC. Please go ahead with your question.

Yeah, thanks. The question was on the cost side of the equation. Is there anything that you guys think you can do in the interim to either reduce costs or are you pretty satisfied with the headcount that you have right now?

Kurt, you know, we feel that we carried some experienced higher salaried personnel during the period of low utilization. So that we would be prepared to go back to a higher utilization pretty quickly. And so, in effect we carried costs that we expect to come-out of the equation when we do that. There’s also, as I said, two other facts in terms of costs. One is that when you put a rig to work you have some incremental costs at the very start of starting it up. And we have additionally the possibility that there may be some roll-back of the 10 percent salary cuts that were put-forward. So there’s kind of three factors. We’re kind of saying in the aggregate we expect them to cancel each other out for relatively flat cost structure against relatively flat revenue structure, yielding relatively flat margins. But there’s actually in that a lot of moving pieces.

Kurt, from our perspective in the field I just don’t think there’s much more that we can cut. We’ve cut everything that we know to cut. And we do have some increasing costs from an insurance standpoint, so you know, I think we’re running bare bones right now. We certainly don’t have a surplus of people other than the ones that Mark spoke of, so I don’t see where we can cut anything else.

Kurt one of the things to add to that is the references Mark was making I think were to the fourth quarter of this year. As you go into next year, assuming we run more average rigs our cost per day would decline, and you know, and Cloyce, bringing his back into it, the cost of insurance is a bit higher, but you know, I don’t know of any reason why our average cost per day wouldn’t get down into that $62, $6,300 range, again, on a greater number of rigs running. I think these comments were more look at the next few months.

Okay. Thank you.

Our next question comes from Marshall Adkins with Raymond James. Please go ahead with your question.

Since you guys don’t have anything else to do today I’m going to ask a couple more questions. First of all, on the capex, correct me if I’m wrong but your capex is down pretty big year-over-year, isn’t it?

Yeah.

Yeah.

And the comments earlier like that it’s up dramatically, my numbers are showing it’s down. Anyway …

Hey, Marshall.

Yes.

It’s up as a comparison against the number of rigs running.

Right, okay.

[Not] up substantially.

All right. Well, let’s talk about that just for a minute. Going forward, when do you start buying drill pipe? When do you anticipate your capex going up? And what should we be modeling really for, you know, kind of Q4 then ’03 on capex?

Marshall, if you went through this, there’s a little bit of laughter here in our conference room because …

I’ve seen the pictures! A lot of drill pipe out there!

Yeah, precisely. A lot of drill pipe out there. We acquired a substantial amount of drill pipe in this year based on an expectation in ’01 of the business continuing and orders being placed, and a decision to proceed with those orders. So we have that significant capacity in drill pipe kind of stacked in the yards. And so, we’re not expecting to be ordering substantial amounts of drill pipe in the near future.

So maybe late ’03? Or even in ’03? Obviously it depends on where activity is, but I mean what’s your gut feel right now?

Late ’03 at the earliest.

Okay.

It’d be subject to the industry – you know, if the business explodes which would be a happy, you know, problem to have then we could be earlier than that. But right now there’s a substantial amount of drill pipe in our yards.

So does it make sense to keep kind of our capex at, you know, 15 million a quarter? Is that a reasonable guess?

Marshall, the way we think about it is that particularly in an upturn the biggest number is going to be driven by drilling operating days, and we think about …

So tie it to that?

You know, $800 or so an operating day when you’re running your model is going to be somewhere, a decent indication of the ongoing capex. And then later on you know, drill pipe could be a more important component of that. And of course, if we refurbish additional rigs to bring them back you’d add that on also.

Right. Pumping services. Mark, you mentioned, you kind of implied that it was a lagging type business. Is it really lagging, or is just kind of less cyclical out there than the rest of the business?

I think I might like your version better, Marshall. Thank you.

Just wanted to make sure that we weren’t looking at a big deterioration in that business next year.

The opposite of that. We’re pretty optimistic about that business in every respect, Marshall.

Yeah, it’s obviously not a huge part of the business, but that’s been one of the bright spots. It’s been remarkably strong.

The last one, you’ve got flat revenues, flat costs, flat margins, and so am I to understand or at least extrapolate next quarter we’re basically looking at another break-even quarter?

Our guess would be it’d be a little better than this quarter, but …

Well, it sounds like there is some off-site inquiries, and if that does translate to …

We expect to run more rigs.

Right. Sure, the Canadian stuff.

Marshall, you know, basically the story of Patterson-UTI is in an industry downturn we broke-even and generated cash.

And that’s not a bad story in a downturn.

You know, when the lows of the business is you basically are break-even and generate positive cash, it’s a pretty good situation to be in, and you have our fleet in a more ready to work, better conditioned, and you know, have personnel ready. We kind of think we did what you’re supposed to do in running a cyclical company in a cyclical industry.

And the up side, John, have you updated your 10,000 margin earnings estimate? $10,000 a day margin earnings estimate?

I think those numbers are still intact.

Still intact, so ’04 maybe?

Marshall, you’re the one that tells us when the activity will occur. We’re just here to try to collect as much money in terms of net income as we can when it happens.

We will look forward to it here shortly. Thanks, guys.

Thank you.

(Caller Instructions.)

Gentlemen, we have no further questions at this time. Please continue.

For all those who participated in the conference call we’d like to thank you for your attention and your questions, and your interest in our company. And we look forward to speaking with you again shortly. Thank you very much. 1