Patterson-UTI Energy Inc (PTEN) 2002 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Patterson-UTI Energy quarterly 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 any time during the conference, please press star followed by the zero. This conference is being recorded today, Tuesday, February 4th, 2003. I would now like to turn the conference over to Mr. Jeff Lloyd, speaking on behalf of Patterson UTI Energy. 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 fourth quarter year-ended December 31, 2002. Participating in 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 Vollmer, senior vice president corporate development. Just a reminder that statements made in this conference call which state the company's or managements' intentions, beliefs or 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 effect demand for the company services and their associated affects on day rates, rig utilization and planned capital expenditures, adverse industry conditions, difficulty in integrating acquisitions, demand for oil and natural gas and ability to remain 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, the report on form 10K for the year ended December 31, 2001 and form 10Q for the 2002 reporting period. Copies of these filings may be obtained by contacting the company or the SEC. And now I will turn the call over to Mark Siegel, Patterson UTI's chairman for some opening remarks to be followed by questions and answers. Mark?

Thank you, Jeff. And welcome to all of our participants. We're very pleased today that Patterson-UTI Energy, the second largest operator of land-based oil and natural gas drilling rigs in North America announced it's financial results for the three and 12 months ended December 31st, 2002. We reported net income of $1.8 million or two cents per share for the three-month period compared to $18.7 million or 24 cents per share for the prior year quarter. Revenue for the quarter was $140.9 million versus $174.7 million for the comparable period in the year before. Net income for the12 months ended December 31 was 2.2 million or three cents per share compared to net income of $164 million or $2.07 per share for the 12 months ended December 31, 2001.

Revenue for the year was $528 million versus $990 million for 2001. Net income for this year includes a charge of $4.7 million, $2.8 million after tax due to the failure of the company's workers compensation carrier for prior years that had -- and net income for the prior year included a charge in connection with the UTI merger.

Turning to Cloyce Talbott, Patterson's Chief Executive comments, the demand we experienced in the third quarter continued in the fourth quarter and has accelerated in the first months of 2003. Our average rigs operating for the fourth quarter increased to 140 including eight in Canada compared 127 average rigs third quarter of which four were in Canada. We are announcing today that going forward we intend to provide monthly reports on average drilling days consistent with our philosophy of trying provide useful and timely information to shareholders. For the month of January 2003 we had 163 rigs operating, including 15 in Canada. Let me add at this point the question that I'm sure we're going to be asked, which is, as of last week, that's the week ending January 31st, we had an average of 175 rigs running of which 16 were in Canada.

As Cloyce said, our policy of retaining our most experienced field personnel and I refurbishing our equipment during the downtimes has began to pay off as we had anticipated. We've been able to respond quickly and efficiently to improving conditions. My comments are we achieve positive results it was clearly a down year for our industry. We generated approximately100 million EBITDA and our balance sheet at year end was even stronger than it was when the year began. As of December 31, 2002, we had no long-term debt, $168 million in working capital, and more than $80 million in available cash allowing us to be -- continue it be prudent and patient buyers when appropriate opportunities arise as was the case of the acquisitions we are announcing today.

Continuing on in regards to those acquisitions, today the company announced the acquisition agreements to acquire seven additional land-based drilling rigs of which six are marketable, along with a yard, top drive, spare drilling equipment, and inventory for a total of $16.5 million in cash. The acquisitions increased the company's rig fleet to 331. Four of the rigs will be marketed in Utah, increasing the company's marketable rigs in the Rocky Mountain region to nine from five, and the remaining rigs will be deployed in south Texas. As we said in our release, the Utah transaction's been completed. The acquisition of the Texas rigs should occur before the end of February.

In Utah, our four additional rigs have depth capacity of between eight and 10,000 feet. In terms of our east and south Texas rigs, reacquired two SCR (ph) rigs, one mechanical, both SCR rigs have 2,000-horsepowerand the mechanical has 750-horsepower. If you allocate one million and a half of the 16 million and half dollars to top drive and the yard, including the land and the building it gives you 2.1 million per rig.

Stepping away from the printed release and our additional comments on it, I just have a few kind of summarizing remarks I'd like to make about 2002 and where we are today. Obviously, in terms of financial results, it was a significantly better year than we expected given the level of rig activity. We're very optimistic now about 2003 as the natural gas market has seen a profound shift from concerns about too much gas in storage to too little gas in storage. In terms of our performance, it was obviously another strong performance by our drilling businesses, and additionally by our E&P and pressure pumping businesses as well.

In terms of sequential improvement, we really had several quarters of very significant sequential improvement and I'd like to spend a minute or two before the question-and-answer session really going through that. Firstly, in terms of average rigs running, in first quarter of this -- of the prior year, 2001, that is -- 2002, I'm sorry, we had 117 rigs running in first quarter. That increased to 119 rigs in second quarter average rigs running again, to 127 rigs in third quarter, and to 140 rigs running on average basis in fourth quarter, and now as we said before, up to 175 rigs running as of last week. In terms of revenue, from a low point in second quarter of 96.5 we saw improvements in third quarter to 100.3 million and then fourth quarter to 109.6 million. In terms of EBITDA, again, a low point in second quarter of 21.2 million with increases to 23.9 million in third quarter and 25.6 million in fourth quarter.

Again, I'd like to reiterate Cloyce's comment that the decision to spend capital expenditure dollars and to maintain our key personnel we believe has been strongly vindicated. And finally, one personal note, I really want to compliment and congratulate the operating management of Patterson UTI for a very fine job done throughout last year. And with that, let me turn it over for questions.

Ladies and gentlemen, at this time, we will begin the question-and-answer session. If you have a question, please press star followed by the one on your push-button phone. If you'd like to decline from the polling process please press star followed by the two. You will have a three-tone prompt acknowledging your selection. Your questions will be pulled in the order they are received. If you are using speaker equipment, you will need to lift the handset before pressing the number. One moment, please, for our first question. Our first question comes from James Wicklund (ph). Please state your company name followed by your question.

Name is Ashish Gupta. Had a question on leading edge day rates. What's the range of these right now and have you seen any pickup in leading age day rates?.

John, want to take that?

Sure. It's really the last several months, rates have been very stable. If you look at the third quarter, the 8600 in the fourth quarter, 8500 is an average revenue per day versus a average day rate. Rates have just been stable for really probably going back to September.

Okay. I just wanted to know, what was your ending rig count at the end of the fourth quarter.

Off the top my head, I don't recall, Ashish. Holidays and things can affect the rig count on any given day. And we think we've good afternoon given you stuff all the way through last week.

Okay. Finally, I guess, if you can go into more detail. You guys talked about how you're going to release the report, your monthly drilling days. If you can just talk a little bit about how this is going to be different for -- I guess financial reporting purposes and how you can kind of reconcile the two.

There's a slight -- you'd be off a handful of days. We use a percentage completion method in turnkeys, in other words for financial reporting purposes, we do not include the revenues from turnkey or the expenses or the drilling days, and the quarter it occurs, it -- it's included in the quarter at which the turnkey's completed. We do not have a high percentage of turnkey work. Therefore, the days we do not believe will be materially different for any period. But it would put you off a handful of days and we thought it was important for you to know that.

Good. Thanks, guys.

Our next question comes from Jim Rollyson. Please state your company name followed by your question.

With Raymond James. Good morning, guys. Mark, you talked about the rig count moving up in your new seven rigs that I guess you'll have closed by the end of the month. Six are marketable it says in your press release. How many are working or do you figure will be working here soon? I presume that's not in your 175 number.

Today it's three or four are working. Four are working today.

Four are working today? Okay.

The other two are workable just relative to closing the transaction. The seller stacked the rates just makes it a simpler transition for them. But two would be ready to go otherwise upon closing.

Okay. The -- for the quarter, your average daily costs came down, which obviously is partly a function of the fact your average rate count went up. But if I recall, you guys also had some weather-related issues in south Texas during the quarter, which usually would have made that number go down. What do are you expecting going forward, say, this quarter or just going forward as the rig count's picking up? Do you expect that to be in flat or coming down or what do you expect on an average daily cost per rig?

For the fourth quarter we think revenues and expenses should be very similar.

So ...

... margin be similar, 18 to 1850 range.

Let me clarify one other thing, Jim, on your earlier question. The rigs that we talked about acquiring here recently, none of that is in the rig count information that we've provided.

Okay. So that's incremental.

Yes.

Your SG&A, just kind of housekeeping, was up in the quarter. Is that kind of year-end stuff or where do you expect that on a good go-forward basis?

Go-forward similar with more rigs running probably a little bit higher. You know, moving maybe to somewhere seven to 7.5 million per quarter.

Okay. And then if you just - then everybody's been talking about this on the other calls, too. If you look at your 331 rigs total, how many today given the recent acquisition could you get up and running or have been running here in the last, say, 24 months and what do you think the cost is to bring those up?

In 2001, we ran 287 of the rigs that we own today. We just acquired six more that are, you know, ready to work for, which as we indicated are working today. So since we didn't cannibalize the downturn, I would say the 293 are ready to run. The rest at 331 would take some amount of investment, which ranges anywhere from a couple hundred thousand dollars to, you know, couple of million or so at the expense of expensive end.

As far as people go, how difficult do you think it is to get enough people to get those up and going as things pick up? .

Jim, this is Cloyce. I kind of go back to the last upturn which was in the end of '99-2000 when we started picking up then, we certainly thought we were going to have a difficult time getting crews for the 287 rigs we had running then. And we did have a difficult time but if you remember, unemployment was much lower than it is today. So -- and we've given quite a bit of wage increases to our field people from that time, so my guess is that, yes, it will be difficult, but we will be able to field crews for our rigs when the need is there.

Just money and time.

Money and time.

Last thing, just you got your rig counts moving up. Your margins you're expecting flat, you know, pressure pumping, I presume is going to be just the normal seasonal change. That kind of implies your first quarter's going to look a little better than your fourth quarter. Do you agree or disagree with that?

Yeah, we agree with that.

Okay. Thanks.

Our next question comes from Neal McAtee. Please state your company name followed by your question.

Good morning, Neal McAtee, Morgan Keegan. Good morning, guys. Could you talk on this -- this is a new statistic so I'm not sure what to ask about. On the drilling days, how many of those days came from turnkey wells that were completed during the quarter? Is that significant -- and I guess the second question along that lines before you answer, what -- are we just going to start with this as the first data point or can we get some more -- some historical numbers just so we have a feel of how to interpret the ones you start releasing.

For the rig counts?

Yeah for the drilling days number.

We hadn't planned to do that. We think about it, I'm not sure what that adds for you. What we think we're doing given the turnkey difference is not -- we believe particularly significant to the quarterly numbers. It's really giving people an opportunity to understand current trend of our rig count which, you know, many people have told us they've had difficulty figuring out from the other sources they have. So for instance, your numbers assume rig's going up 20 rigs quarter to quarter or 30 rigs whatever it might be, you get incremental data points as you move toward that to understand the actual direction of the rig count. I don't understand why the historical would be helpful, but we'll think about it.

Okay. Well, and I guess given the statement before the paragraph where you say that the total differ from monthly drilling days considered in determined revenues expenses, then I guess continue on that discussion, you would argue that given out the historical data and us trying to draw some conclusion between the his historical data and revenues so that we could extrapolate some numbers you released, it wouldn't be useful.

Yeah, I think your -- I think you'll find that you're raising too much concern from the sentence. We felt the --it will differ, you know, in any given period, it could be10 or 15 days difference, because you have a turnkey starting, a turnkey ending.

Right.

We don't think it will be bigger than that.

Right.

But if we put out January, February, and marriage, and it's off by 10 days in the quarter we don't want you to think we don't know thousand count so we needed to point that out. We do not think it will have a material impact on your conclusion.

Let me just add one thing. I think we're getting lost here in a extremely small detail on a very large point. We if think that in terms of this number for the month of January, somebody correct me if I'm wrong here, would have been less than a half of rig in terms of the number of average rigs running. So the sentence you're talking about with regard to how to measure turnkeys and so in effect, it would have looked like if you added the three months together potentially there was a rounding problem. And the reason for the second sentence just about methodology was just so you would understand the methodology point, and you would have a very clear sign. But in terms of this number, our real point here we think is that as you can understand 163 rigs running ...

163 is reported ...

Right. ... is reported against say the end of the quarter, we're really giving you a very important piece of information in terms of long-term or monthly trend potentially which we think's far more valuable than anything out there and that has been given any of the other drillers. Sew we feel like we're trying provide a fundamental service to the investment community. And the question of whether it's going to round a half a rig each way because of this turnkey accounting practice that's consistent with the industry is really the only question.

No, that's great. And I mean, is there -- what -- is there a planned release within so many days after the month or the last day of the month?

Within three business days we plan to report.

All right.

Just to give you some final clarity on this, we would add 15 more days on the financial accounting basis, which is basically a half a rig higher.

Right.

So we just -- we don't think it's going to be material.

Right. No, I -- that's -- that's great. I think that's -- I think it's good to start doing it. Thanks, guys.

Thank you.

Our next question comes from Roger Reed (ph). Please state your company name followed by your question.

Roger Reed with Simmons & Company. Good morning, gentlemen.

Hello, Roger.

Couple questions for you. Looking at the margins in the first quarter, seems like you're being fairly conservative. We've got the rig count definitely up, looking at the current one of 175 plus the four, and then you've also got Canada seasonally strong. Shouldn't that push the margins slightly higher than 1800, 1850 range in the first quarter?

You know, we spent the day before this conference call among our management thinking it all through, and you know, give or take $50, we think it will be flat quarter to quarter.

Why is that? I mean, given that Canada is seasonally stronger and I think we've got kind of rate expectations four to 5,000 depending on your competitors, I mean you must see that flowing through as well. Right?

Yeah, margins of Canada are slightly higher, but we have 16 rigs and you can't run every one every day. So if you assume on average for the quarter were going to average 14, anything -- I mean, 15 is -- that's pretty heavily utilized. That isn't real large to our total drilling operation. You know, it may be for some of the other drillers who have a bigger presence in Canada. You know, the average rigs running for last quarter was eight. It's just not going to have a huge impact.

Okay. And then ...

And Roger, one other kind of point, we're beginning to run more and more rigs at ramp, you know, period to period, as you could see is very significant. And you certainly do incur some costs to bring out a rig. It's not -- you know, it's not real large but you aren't necessarily getting to bill for your work the moment that the people go on the payroll. And if you look at the upturn in '99, you would find that each of the Capitol drillers incurred slightly higher costs as they were bringing out rigs until they stabilized that count. So, you know, that's probably a little bit of an awe setting factor to Canada at the same time.

Okay. So mobilization costs essentially.

Yeah, just start-up.

Okay. And then in terms of if you get rig count obviously tricking higher here, what do you have in the way of visibility right now or inquiries for your both marketed and any rigs that you might bring back here in the next several months?

This is Cloyce -- we're getting far more phone calls from our customers today than we were a month ago. So that would lead us to believe that we're going to - with inquiries that we're going to have more rigs working as we go forward. It's probably a function of the cash flows that our customers are generating with these higher commodity prices.

Do you care to quantify that increase?

It would be a guess to quantify it. So I -- all I know is talking to our salesmen, we're having a lot more calls than we did a month ago.

Okay. Thank you.

Our next question comes from Andy Vietor. Please state your company name followed by your question.

Good morning. Andy Vietor, Stifel Nicolaus. You can quantify your potential backlog on your rigs you're running right now? One of your competitors put it as sort of an average of in excess of 5 1/2 weeks per rig in terms of backlog. I was wondering if you guys could put the same number on your backlog.

Don't think we could do that at all. We have such a wide spectrum of rigs running that some of them have days and some of them have months. So I don't even think I'd hazard a guess at that.

Okay.

Andy, we follow the policy, though, that we try not to put a rig out unless we believe we can keep it working. We're not always correct in that, but that's certainly the goal that our operations people follow.

Okay. And as we look forward here in --you're not expecting much movement at all in the first quarter in terms of rates and margins, where do you think the inflection point is and once you reach that inflection point what type of change do you think you'll see in rates and margins?

You know, Andy, we're as interested in that question as anybody is. Cloyce likes to say our customers set our drilling rates and I think there's a lot of truth to that, because obviously, as demand reaches is certain tipping point in the market and there's a perception of scarcity we see that change in pricing. You know, the real question is at what level of utilization that occurs, and we saw that during the last uptick at somewhere between 50 and 60 percent of the entire rig fleet. But it has to be where in effect all the fleet and all of the competitors' fleets are at that same sort of level of utilization. So we think we're a little ways away from that at this point although we certainly expect it to occur.

Would that be of total available rigs or total marketed rigs?.

Marketed.

Marketed. Okay. And just so -- one quick point of clarification. Do you say the two SCR rigs in Texas are 4,000-horsepower?

No.

I'm sorry.

2,000-horsepower.

2,000-horsepower. Thank you guys.

Our next question comes from Ted Grace. Please state your company name followed by your question.

Hey, guys. It's Ted Grace with Goldman Sachs. Just hoping to get a little more color, just looking a little more closely at the daily average revenue on a sequential basis down marginally. Just wondering if that's a function of the type of wells drilled or you've seen some marginal deterioration of rates?

Probably a little of both. I think it's a practical matter to have the pricing stabilized toward the late summer, early fall. You know, all that's got to run through the work and $100 movement we don't view as at all significant. And it's -- I don't have a precise number off the top my head but there's probably a little more than $100 in the U.S. and then Canada picking up a little bit going the other way. And I think Canada, you know, probably contributed $50 of extra margin on average for the quarter.

Okay. Great. In terms of customer(inaudible) just wondering if you've seen a bump from 140 to 163 to currently 175, just any shift from, you know, a greater portion towards the mid cap independents or large cap independents from the primary emphasis privates?

Cloyce, you want to take that?

You know, we're certainly seeing an increase from both of them, but I don't think that I could quantify it to you which one is increased more, but we are seeing an increase from both the larger cap and the privates.

Okay. And then I guess one other thing we were hoping to ask you is, if you could comment on the types of wells that are being drilled now, if there's any change shallow versus deep, oil invest us gas, just to get a sense of the wells you're drilling as well as maybe some geographic sense to get a sense of any pockets of strength or weakness.

Versus when, Ted?

I guess in the fourth quarter sequentially as well as thus far -- you know, through January.

To answer your question about the areas, we're seeing increases in all areas. Historically what I've noticed is the higher the come commodity prices the shallower the(inaudible) that's all because of economics. You think it would be the opposite but over the years if you'll go back and look when we have high commodity prices and high utilization wells tend to get shallower during that time. So I don't think there's any -- I don't think there's any significant change where that's been in the past. We're drilling more for gas than oil as you might suspect.

Okay. And then notice that depreciation was down sequentially. Wonder if anything you could provide some color there as well as guidance for '03.

In terms of guidance '03, you know, some depends on the activity and cap ex for the period, but somewhere in the95 to 97, 98 million for the year is what we initially are thinking. Do you have any comment?

I just might add a little bit to that. If you're looking at DD&A (ph) in total, we took some additional (inaudible) impairment expense in 2001 that on a comparative year basis would indicate some change, and that increase depletion in part was driven by (inaudible)at the end of the year. Versus commodity prices at the end of this year.

Okay.

You know, we have small A&P business.

Yep. Okay. Great. Thank you very much.

Our next question comes from Jim Lewis. Please state your company name followed by your question.

Caller: It's Morgan Stanley, and I guess my finger needs to get faster, because most of my questions have been answered, and it just leaves me with something pretty uninteresting. I'm just wondering, in the guidance category, what G&A looks like. It obviously stepped up in the fourth quarter, and I assume that's bonus related. What's a good run rate for G&A going forward for the next several quarters?

You know, probably it's driven by rig activity obviously. You know, our thinking is, you know, 7 to7.5 million a quarter assuming we're running the number of rigs we are today or a little more than that. And actually I believe it was not bonus related, but it it's just costs associated with getting rigs running a little higher activity level.

Okay. So just tied to revenue more than anything.

Yeah, you can't do a direct tie there because once you get a number of rigs running, G&A is pretty much a fixed cost. But there certainly are differences from running 120 rigs to working your way up to 1 running 160 or 170.

At what point does clearly as your number of rigs running goes up, your average cost per day at least once you sort of absorb the deployment costs should continue to go down because of absorbing sort of your underutilized personnel that you kept on the payroll. At what sort of rig count number does all that, you know, sort of excess people capacity go away and you need to go out and really add new hands across the board and you'd be experiencing, I assume, once that happens, the opposite pressures on your costs.

Yeah, our -- yes on the current cost structure. The cost per day bottom, you know, assuming there's no other fundamental changes in cost, somewhere in the 62 to $6,300 a day range, not higher than say 6350. That's a little higher than last time driven by higher insurance costs everyone's experienced in all industries. You know, the exact point we get there, Jim, you know, we don't know. It's hard to figure. It's how quickly the rigs go out and how efficiently and how well they stay out there once, you know, you put one out. But you know, last time I believe our costs bottomed off the top of my head, I think it was first or second quarter of 2001, and you know, as we get out and get to running, you know, 200 or more rigs, we would expect costs would begin to get lower than what we saw in the fourth quarter.

But some of that's dependent on how quickly it happens. Right? You your costs would tend to be stable and decreasing if activities increasing in a somewhat orderly manner but when things get real hyper, that tends to throw your costs out of whack. Is that a fair statement?

I think what -- you know, you've seen last quarter and I suspect you'd see in the first quarter is that we're running more rigs, more constantly, which in that(inaudible) we're getting some cost benefit. On the other hand we incur some costs to bring additional rigs out. So, you know, in the first quarter, that's why, you know, we think the costs are going to be pretty much flat quarter, quarter benefit in Canada and a little bit of detriment in bringing more rigs out. As you look to the second quarter, you know, we got the seasonal factor that everyone needs to remember, that Canada goes on vacation with the (inaudible) period.

And, you know, we'll lose somewhere in the neighborhood of going from an average of, say, 14 or 15 rigs in the first quarter to somewhere closer to, you know, 3 or 4 rigs in had the second, which, you know, hopefully U.S. rig will kind of offset that so sequentially we would have a similar if not increases rig count but that again would be a drag on daily costs per day. On the other hand, if you believe that we're going to run a few more rigs in the U.S. as we move to second quarter, that should offset that and again get you about the same cost per day. Depending on what you believe about the third quarter, you know, with gas prices, north of $5, you know, if our customers continue to work more when we hit that period, we should start to see a decrease in cost per day at that point, because Canada, starts to come back to work and become more normalized and then hopefully we're running more rigs and our fixed costs are more efficient also.

Got you. Last question is, what's the -- what do you expect the incremental DD&A from this - these rig acquisitions will be?

Generally -- you know, we have -- we haven't done the step that will bring us the precise answer which is we take the inventories, lay them into our fixed asset system and apply all the appropriate lies to each of the individual components of the rigs. But generally, what we find is that it's a little bit more than 10 years on a rig acquisition typically. You know, somewhere in the kind of10 to 12-year range. And if, you know, back then (inaudible) use 11 if I were you.

Okay. 11 years and would you apply that to your full acquisition costs or ...

You know, some land was acquired, you know, which you don't depreciate. We acquired additional yard there.

Top drive which is probably four years.

Yeah. With top drive, I think it's probably five years, I would guess. I think that's five years of use they need a major overhaul so it will be sequentially in terms of -- it will be less than -- I mean, it's not a big number on a quarterly basis no, I wouldn't think so.

Okay.

And the spare components we acquired a lot of loose parts so to speak. That stuff affects inventory. It sits there and when it goes on a rig, you start depreciating it and until then, it's really inventory. But most the costs are going to be allocated to the rigs. Off my head, probably -- you know, mark used 15 million, that's pretty close. It might be a little less than that once we get all the detail put in our system.

Got you. Thanks a lot.

Thanks, Jim.

Our next question comes from Geoff Kieburtz. Please state your company followed by your question.

It's Salomon Smith Barney. You've exhausted nearly the discussion on cost trends. Just one question on that. Is there anything other than insurance costs that are showing any pronounced upward trend?

No.

No.

Okay. Can you give us some idea of what you're expecting to spend in capital expenditures for '03and also given your outlook what you expect working capital either requirements -- I guess requirements might be?

In terms of cap ex, we're looking at an expectation for next year of approximately the same spending as in last year. That's about $70 million expected to be spent in drilling, approximately $15 million in the three other businesses. Obviously, to the extent to which we get to a situation in which we're bringing out rigs over and above the 287 that we ran last time increased to 293 by the current acquisitions, then we would have incremental capex to in effect mobilize those additional rigs. But we're looking this year at a budget similar to last year, taking into account that we bought a lot of new drill pipe last year, which we don't expect to be buying this year, but that's going to be offset by greater number of rigs running and the cap ex to keep those rigs running.

Okay. And the working capital?

It's kind of -- it just depends how quickly rigs come out. Basically, you know, we bill our work on 30-dayterms, you know, people tend to pay until 30, sometimes 40-day range. We pay our costs a little faster than that. So there is some impact to bringing out more rigs, and you know investment in net working capital. But to pin a number on it, you have to say how quick the rigs are going out, because, with you know, if you're putting them out there profitably and ramp is slow, you basically have no real meaningful additional investment or working capital. We have no concerns about our ability to fund any working capital requirements even if we went to --.

Sure.

... spending all our rigs next quarter. We have good cash position in the $80 million range, we have$100 million line of credit. And you know, we think if we needed more credit for that or acquisitions we have great balance sheet to get it. So I can't pin it number on it for you, but we're certainly well situated to accommodate whatever the needs are.

Well, actually, you touched on one of my other questions, which is, you know, can you -- in this environment sort of characterize whether consolidation opportunities are becoming broader and more numbered, or is it working in the opposite direction?

It's -- I think it's always been similar. It's a matter if you find a seller that will sell for a price that makes sense for our shareholders, we are very focused on making each transaction accretive to our shareholders. And, you know, 2002 is a period for whatever reason where not a lot of transactions closed. In our case we acquired five rigs, starting the year out with, you know, link together a couple transactions, picked up seven rigs. We've done big ones. We've done little ones. Where ever we can find an accretive opportunity to buy rigs, we do.

Okay. No obvious change in the market - you know, conditions in terms of consolidation?

No.

Okay. And then just the last question, this was kind of touched on earlier, but if you just focused on, say, the last 30 or 35 rigs that you have put to work, is there any clear characteristic that differs from the rigs that you already have at work either in terms of the type of rig that's being called for, the customer or the locations?

No difference in customer. No difference in location. Just more rigs running.

Very good. Thank you.

Our next question comes from Amin Billie (ph). Please state your company name followed by your question.

... good morning, guys.

Good morning.

Is that all you can give us an update to one of your (inaudible) inventory or are you -- are you -

Could you speak up a little bit? We're having trouble ...

Yes, hi. You can hear me now?

Yes.

I was wonder if anything you could update us on your drill pipe inventory and whether you're going out there with new orders or you're using old inventory? How many days of inventory do you have?.

We have a substantial quantity of drill pipe. We acquired a substantial quantity of drill pipe last year and the prior year. And we're not expecting to be acquiring drill pipe at this point for quite a while.

It's about -- you know, depending on utilization it's 12, 13 months.

Thanks a lot.

Ladies and gentlemen, once again, if you have an audio question, please press star followed by the one at this time. And our next question comes from Marshall Adkins. Please state your company name followed by your question.

Raymond James. That top drive depreciation schedule effects, our numbers are all in trouble. Double quick one here's. (inaudible), you can give us an update on that investment and kind of what your strategy is there and what's going on there?

Sure. The update is it's real really no change from what we've said publicly before, which is that we remain a significant shareholder in the company. We have found the management to be cooperative and informative to us as significant shareholders. That's pretty much the - about as much as we can say. There's been nothing -- no changes and no developments.

Okay. Pressure pumping and fluids. I assume you're seeing, you know, a similar type pickup in those businesses, obviously adjusting with the regional characteristics but a similar type pickup in the rigs. Is that fair?

Fluids, you know a lot of the volume in our fluids business is tied to the gulf of Mexico, which I don't think has been going, you know, up the way the land rig count has. But I think that business is probably more stable versus increasing. And you know, pressure pumping side, the northeast is where we're -- we do that work. And you know, they're very commodity price affected as we all are. I would suspect the commodity prices stay high and the inventories stay low that as we move into summer, you know, they would is have a nice second half of the year for the rest of this quarter, for this quarter, I would think it would be, you know, similar to last year, a little bit better. And second quarter with our pressure pumping business is always a tough call because it's greatly weather driven.

And as you know, Marshall, it tends to have a little bit of seasonal decrease and then they come on and some are real strong going into the winter for third and fourth quarter.

All right. Very much like Canada. I assume ...

Yes.

-- on the can Canadian side you're still looking at the usual seasonal decline there. Nothing different that you're sensing is (inaudible) there. Correct?

Not where we drill, yeah. We would expect -- we're really highly utilized right now and have been since late November, which frankly is an early stator start for condition Canada at least in our several years experience and we're very highly utilized there now. But second quarter I don't think we've ever seen an exception in our experience in Canada that it's going to drop to kind of three rigs, somewhere thereabouts, and then summer, you know, will tend to move up more toward the -- that's the one (inaudible) more variable but you're going to move up seven, eight, maybe nine rigs.

Oh. You guys mentioned, you know, a little bit on where your industry utilization needs to be before you seek pricing move. Let me ask that question a different way, more specifically, to you. You've seen a huge ramp-up in your rig count in the past several months. At what point -- at what point in time do you say, okay, we're not putting any more rigs out there unless we're getting meaningfully better prices. Are we close to that or should we look for another 20 or 30 rigs before you guys say, hey, enough until we get better prices?

Well, Marshall, we, of course, love to be able to get better prices today. But obviously, the pricing - you know, our market marketplace is not something which we control. It's driven by the competitive factors of our competitors' ability to in effect put additional rigs to work as well as our ability to put additional rigs to work. And so at this point, we're not seeing significant, you know, decisions on our -- on other parties' parts to in effect withhold rigs and I think rigs are going into the marketplace in an orderly fashion, but at this point, there are still rigs available from our competitors and so there's not the pricing change, the pricing environment that would allow for change in our behalf. I said in an answer to Andy Vietor's question that we saw historically50 percent to 60 percent, he asked me marketed? I said marketed. I really should have said total rig at that point about but that's historically when it's occurred. It's pretty hard for us to make a judgment as to exactly when that's going to occur. Obviously, there's a - still a significant number of rigs available in the marketplace able to go to work and so we're not seeing that change yet.

Okay. So no specific rig count number for you for you really start to push it.

Right.

I don't think so, Marshall.

All right. Last one to try to get you to push you over the edge here. The consensus forecasts are all over the board for 82 guys and obviously the - for you guys and obviously the amount of leverage you guys have to pricing and rig count assumptions, once a pretty widespread. But you know, let's say gas holds at 5. I mean, our numbers showing you're not -- there's no way you're doing anything less than 50 cents this year. Can you comment on that? You can give us any kind of - can you give us any kind of band or guidance on the full year?

Yeah, Marshall, we try not to give guidance. We think that it's greatly an industry call. You know, on the other hand, when we look at things internally, you know, we right now feel similar to you that, you know, it's --we're going to earn something north of 50 cents. But that assumes that the rig count's going to increase later in the year. And we don't know if that's correct or not correct. We would hope that you are right with $5 gas prices below inventory. But, you know, it makes a lot of sense for our customers to drill. But that's -- you know yet to be seen.

It does seem like we're (inaudible) on their(inaudible) today and those guys seem to be upping their forecasts through the year. So gas holds in there, we'll look forward to it. Guys, thanks. Appreciate the insights.

Thank you.

Our next question comes from Kurt Hallead. Please state your company name followed by your question.

That's Kurt Hallead, RBC. Hi, guys.

Hi, Kurt.

Just a quick question. I wanted to - you mentioned -- if you mentioned it already, I apologize. I hopped on a little bit late. In terms of bag lock of projects, are you guys sitting on opportunities, two or three deep for your rigs yet, or is that really just starting to build as we speak?

The answer we gave earlier to that, someone asked that if and it's really difficult for us to quantify what our backlog is. Someone had given so many days per rig because we have so many rigs that drill varying projects. We look at it more whether the rig is contracted, you know, for extend period of time is our backlog rather than days. And I don't have an answer for it. We really do not have an answer. I think we kind of look at more inquiries from -- on a go go-forward basis and we've seen that, too.

Just out of curiosity, I was wondering if you're getting any feedback from the clients that are utilizing your rigs on land as to why we're seeing a dichotomy in rig count, you know, land versus offshore. Just wondering if you're hearing any kind of scuttle button the field or from your customers as to why they're putting more land rigs to work than they are, say, in the Gulf of Mexico? And if not -

We haven't heard anything, Kurt.

Okay. All right. That's it for me. Thanks.

Our next question comes from Joe Agular. Please state your company name followed by your question.

Johnson Rice. What's the strongest reason or tightest reason for you guys right now?

Really they're all just about the same. I mean, we're seeing rig count increases and we're certainly not seen (ph) percent utilized in any of the areas that we're working in, and I couldn't pick one that's -- that -- that's better.

No area really sticks out more than the other, it sounds like.

No, that's correct.

And again, I don't know if you gave this. Could you tell us how many rigs you could crew up today?

Well, we worked -- you know, this past year -- how many rigs we worked this past year? Two ...

287.

230 this past year. My guess is that we'd we probably have crews right now in the range of 190 to 200 crews would be my guess.

Okay. So the transition to a number in that range should happen would be fairly smooth for you guys.

Yes.

Okay. Thank you.

Our next question comes from Matt. Please state your company name.

It's Matt Conlon (ph) from Weiden and company. And Marshall already elicited the vague and noncommittal response to the timber sharp investments you have. I wanted to turn the screws on you a little bit more. As I see it, there are two ways that you can guys can show some net income from what investment, either by increasing the ownership above 20 percent and getting the equity income or looking to sell the stock when it gets to higher level. And right now you're in neither one of those places, and I can't really believe that you're happy in neither one of those places.

You know, Matt, it's time -- at the time this thing was done we planned our thinking and I don't believe that thinking has changed. It's both offensive and defensive, and we can remind everybody what that that was, you know, timber sharp is a good quality company, in west Texas, and, you know, they charge for their services. And the defensive move was that Joe Roper died (ph). His family owned, you know, roughly 20 percent of the company, and that --those shares are going to trade. And we felt that those were better in our hands than somebody else's. And we took, you know, cash sitting on our balance sheet that was not particularly accretive at interest rates today and we converted that into timber shares. On the other hand, you know, Patterson, UTI and I'm sure many other people have talk talked to Tom Brown on a variety of dates about acquiring the company. And you know, he would talk to people but wasn't interested in doing that. So we're a patient shareholder. And if they want do something at some point, you know, we disclosed all that we would certainly talk to them. But you know, I think we're happy with our investment. We think we paid a reasonable price to take a nice stake in a good company who runs their business well.

Okay. Thanks.

Our next question comes from John Debs (ph). Please state your company name.

John Debs, Voter Capital Management. I noticed Enron (ph) sent report that the Chevron was down to five rigs, Exxon 10, I think BP Amoco, (inaudible) and so on. Can you give us some insight into, I guess, the three categories you have, the majors, the large independents and then the smaller independents if you're seeing the improvement across the board or what trends are you seeing in your different types of customers? Thank you.

I think we've historically said that the majors amount to about 6 percent. The major independents to 34 percent. And the kind of non-public companies that we do a lot of work for, about 60 percent. He, as Cloyce said earlier, we've seen some improvement as our rig count's good night gone to 175 as of the prior week. Each of those categories -- week in each of those categories. But we can't say that we've seen a dramatic uptick in any one of those particular categories above any of those categories.

You can talk a little bit about do you any in the different categories whether they will spend their cash flows this year as they have historically, or given the new conservativism you hear especially from some of the bigger independents, whether you think there's going to be a change in industry practices.

With high $5 natural gas prices and over $30 crude oil prices we could expect the -- our customers to want to drill and to want to harvest the hydrocarbons that they can harvest under this price (inaudible) for the commodities. I can't say whether they want 0 spend their money or not. We find out about it if they do it and we can't predict too well.

Thanks very much.

Our next question comes from Hail Oak (ph). Please state your company name followed by your question.

My question's been answered. Thank you.

Thank you. Our next question comes from James Wicklund. Please state your company name followed by your question.

Have you all close out your safety record for'02 yet?

To, we have not closed it out. I can tell you certainly improving, though.

You can give us like on a workmen's comp modifier or something or however you look at it, you compare your safety record to like '01?

Jim, we don't have any of that stuff with us. We'd be doing it off the top of our heads.

Okay.

I apologize.

Okay. The impression I get, know, with John sometimes it's hard to tell, but I would say basically you guys seem optimistic?

About safety or about ...

No, about business. I'm sorry. I know you're optimistic about safety.

We're optimistic about both, Jim.

There you go. You by mean, you guys have given a lot of information, but you're basically optimistic that drilling's picking up. Is that right?

Very definitely so.

Okay. Cloyce, you've been doing this awhile. When drilling picks up like this, how long do these pickups usually last? A quarter, two quarters?

Well ...

Two years?

The last few have been ups and downs have been, you know, in the range of a year and a half, two years. And it's certainly always driven up and down by the commodity prices.

Yeah. I understand. So if we're just now starting this pickup and you say, the last several have been 18 -- you know, 12 to 18 months or two years or something?

Yeah.

Without caring about commodity prices particularly, would you expect this one to last that long this time?

I certainly expect it to. Probably eight, nine quarters.

Okay. And ...

I think last time it ran about nine quarters.

Okay.

On our numbers.

And I just want you to know I'm a good customer, rig 84 worked the entire way through the fourth quarter and it's still working. Just don't raise prices on that rig. Do me a favor. Okay. Gentlemen, thanks.

Thanks.

ladies and gentlemen, if there are any additional questions, please press star followed by the one at this time. As a reminder, if you are using speaker equipment, you will need to lift the handset before pressing the numbers. At this time, there are no additional questions. Please continue.

We'd like to thank everybody for their participation in the call. And look forward to next quarter's report. Thank you, everybody.

Thank you, sir. Ladies and gentlemen, this concludes today's Patterson-UTI Energy quarter earnings conference call. If you would like to listen to a replay of today's conference, please dial 1-800-405-2236 or 30throw 3. 590-3,000 followed by access number 520689. Once again, if you would like to listen to a replay of today's conference, please dial 1-800-405-2236 or303-590-3000 followed by access number 520689. We thank you for participating. You may now disconnect.