Patterson-UTI Energy Inc (PTEN) 2004 Q3 法說會逐字稿

Good morning, ladies and gentlemen. 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. (OPERATOR INSTRUCTIONS). As a reminder, this conference is being recorded today, Thursday, October 28, 2004.

I would now like to turn the call over to Jeff Boye (ph) on behalf of Patterson-UTI Energy. Please go ahead, sir.

Thank you very much. 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 three and nine months ended September 30th, 2004. 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 brief 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 the associated effect on day rates, rig utilization, and planned capital expenditures; adverse industry conditions; difficulty in integrating the 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 to the Company's SEC filings. 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?

Thank you, Jeff. Good morning, and thank you for joining us today. I hope that by now you've all had an opportunity to read our earnings release. Before taking your questions, I'd like to take a couple of minutes to review some of the highlights from the release and to add some context to the results.

First, we are pleased to report that we achieved a significant jump in activity as we operated an average of 216 rigs during the quarter as compared to 203 rigs in the second quarter of this year.

Second, we believe that in the current quarter, the activity level will continue to increase. Despite wet weather conditions, which slowed activity in October, and an expected slowdown for the Christmas and New Years holidays, we expect that we will average approximately 225 rigs operating for the quarter. We think we'll average approximately 219 rigs operating for October, and by comparison, we have averaged more than 230 rigs operating for the last week. Assuming that we achieve this approximate level of 225 rigs, then we will have seen average rigs increase in the four quarter of 2004 from 197 to 203 to 216 to approximately 225 rigs.

Third, we saw an accelerating increase in margins in the third quarter of 2004 as we achieved average margin per operating day of $3320, a sequential increase of $400 per day. This marks the eighth consecutive quarter in which we've seen an increase in margin per day.

Fourth, the long uptrend in activity has allowed us to train a large number of crews, which permits us to maintain efficiencies for our customers while operating more than 230 rigs. This added efficiency, coupled with high commodity prices, is resulting in continuing day rate increases as the supply of available rigs has declined. We continue to see strong demand for our rigs, and we would expect that margins would increase in the current quarter by an additional $500 per day.

Fifth, our smaller business units, pressure pumping, fluids and E&P, all performed in an outstanding manner in the quarter. In fact, our pressure pumping and E&P businesses each achieved record quarters in terms of revenue and operating income.

Sixth, reflecting our Board's continuing confidence in our business, the Company declared a $0.02 cash dividend with a record date of November 15th, payable on December 1st.

Now, I'd like to highlight our financial results. For the quarter, net income increased to $30 million or $0.18 per share compared to 17.2 million or $0.10 per share for the third quarter of 2003. Revenues for the three month period rose to 259.2 million versus revenues of 207 million for the quarter ended September 30th, 2003.

Net income for the nine month period increased 95% to 70.3 million or $0.42 per share from 36 million, or $0.22 per share for the comparable nine month period in 2003.

Revenues for the nine months increased 25% to 712.5 million compared to revenues of 567.9 million for the nine months ended September 30th, 2003. Sequentially, net income in the third quarter increased 53% compared to the second quarter of 2004.

Before turning to questions, I would now like to ask Cloyce Talbott, the Company's CEO, to comment. Cloyce?

As many of you know, I have spent more than 40 years working in the oil service industry. I have not seen the business fundamentals this strong ever. In light of the existing shortage of natural gas production in the U.S. and the apparent capacity constraints on crude oil in the world, I would expect that demand for our service will continue and gain strength going forward.

At this point, we would like to open the call for questions.

(OPERATOR INSTRUCTIONS). Geoff Kieburtz, Smith Barney.

Two questions really -- sequentially you had pretty strong incremental margins. And as you mentioned, an accelerating margin improvement. Do you expect that you're going to continue to see acceleration here? Or is this a new level you expect to sustain?

We would expect the margins to continue to increase as day rates continue to accelerate. We reached a point where the available rigs have become short. In fact, if you were listening to our call the last quarter, we thought we would see this shortage of drilling rigs in the fourth quarter, which actually occurred a little earlier than what we had anticipated. It happened at the end of the third quarter. And we are seeing a real shortage of rigs. And I would think you would continue to see some increases in accelerate (ph).

I was really referring more to the pace at which margin was increasing. I think we'd all agree that margins are going to continue to increase here. But as you pointed out, or was pointed out in the opening comments, the pace at which margins are expanding has grown. Do you expect it to continue growing or grow on a quarterly basis at the $400 a day that we saw this quarter?

That's nearly impossible for us to indicate quarter by quarter looking out 2, 3, 4 quarters just what the increase will be. That will depend on the demand at that time. What we have seen, and put it back to the historical context a little bit, is our margins first began to move in a meaningful way in the second quarter of 2003. We continued to get smaller increases in margins over the quarters after that time. And what we believe we have now seen, particularly here recently, is reacceleration of margins as the industry has run out of rigs. It's a practical matter that we are available to run today. All the incremental rigs are in the hands of Patterson and Nabors, I believe, has a nice number of rigs that they can bring back over time. But those rigs cannot be brought back quickly, and that constraint on supply we think will result in higher day rates as long as we continue to provide a quality service.

So as we look out, our thought is $500 a day, could be a little better in the fourth quarter. As we look into next year, we don't know, but we would think rate increases similar to that over the following quarters would make sense in a supply-constrained environment.

And Cloyce, I'm going to ask you a question related to the comment John made there, regarding quality. We talked to a number of operators out there -- they seem to be pretty comfortable with the rate increases, but increasingly we're hearing about concerns regarding quality. From your prospective, how do you ensure that the crews that you're putting out on these rigs that you are activating are maintaining that quality and efficiency of operations?

That's been one of our concerns, to not let happen this time what happened to us in 2001 when we got very inefficient with the growth in the rig count. And I've watched it so far this year -- the last two years, actually -- and have been very conscious of it as we went along. And we have been trying crews; the industry has been training crews in a slow, methodical manner. I look at the daily billing reports on a daily basis when I'm in Snyder, and it's amazing the efficiency that we've maintained. In fact, we've even increased the efficiency, where we are drilling wells faster in some areas than we previously did. I've been real, real pleased with it.

One of the things you've got to be real careful with is the quality of the equipment you put out as you come out. We've been doing that very slowly. We've spent a lot of money on it. We are putting out fine equipment for the crews to work with, and we want to work in a very safe manner. I've been excited and pleased about the manner that we've grown our company this time. And I think it's going to continue as we go forward, because I think we are very methodical the way we're doing it, and we've got to do it in a safe manner. We've got to be safe with the equipment we put out, and we are putting out quality equipment when it goes out.

As you project the current trends going forward for the next several quarters, do you see the primary capacity constraint being more on the equipment or more on the people?

I think it's more on the equipment than the people. I think the people we're going to be able to train and have available. There will be some areas that might be a little bit more difficult than others, but it just takes time to get the quality equipment out that the people want. Sometimes we have a difficult time getting the parts we want -- (indiscernible) pumps, for instance, they're a slow process. But we're managing it, and I think we are maintaining efficiency. I've been real pleased with that.

And final question, what does these conditions do to your plans for capital expenditures?

Of course, we will probably increase our capital expenditures slightly. The last two quarters we're about the same, we're spending about the same, and that's what we think we'll do going forward, at least for this quarter, and maybe the first quarter of 2005. After that, I'm not sure that we can tell you what it would be, but I wouldn't anticipate it being any more than what we've done in the last quarter or two.

Marshall Adkins, what Raymond James.

Over the past year and a half or so, you guys have been one of the more responsible players in the industry, pushing, it appears, pricing more than utilization. And finally we've got to the point where we are seeing that pricing move up in an accelerating fashion. The question is -- in theory, you have a lot more rigs you could bring out. Can you walk me through your thought process and how soon you would be bringing those additional rigs out? How many rigs there are in your portfolio that you could bring out? Give me a sense of how you see that progressing, and how that fits into the pricing scenario you just outlined.

We have, you know, roughly 100 rigs, a little over 100 rigs to bring out into the marketplace. There's several things that come into play when you bring a rig out. First, it's the type of rig that the customer wants for the area it's going to. And the horsepower the want, the rating of the derricks. You combine all of those and you put that piece of equipment together for that area. And to give you an idea of how we see it happening, last quarter we were working on five. We actually had five rigs, and I think one of them has just gone out, and we are working on four right now, and we're planning on bringing another on. We actually work on about five rigs at a time.

Again, like I said earlier on the previous question, it's a very methodical method we have. And it's doing it for not only for quality of equipment, but for safety for our employees, and giving us time to train employees and get them out. To give you an idea, I think if demand stays like it is now, I think you'd see us putting five -- maybe every quarter, maybe 10 rigs a quarter. That's kind of what we're seeing. Some of them will go out a little quicker because we don't have to do quite as much work to them. For example, we just moved a rig to the Rockies, and it didn't take very long to get it out. It took less than 30 days to get that rig out. Because of the quality -- what they wanted. We had to winterize it and put a boiler on it, but it's that type of stuff. It's difficult to just say you are going to do a number without knowing where you're going and what you're taking to that area.

It sounds like even if you are putting out five to 10 rigs a quarter, you're still looking at being able to push pricing increases plus or minus 500 bucks a quarter and going forward. Is that fair?

Marshall, if things stay like they are right now, we can't get to what we're doing, and we are getting requests for rigs everywhere. Assuming that the commodity prices stay anywhere close to where they are, and the demand stays anywhere close to where it is, the day rates will probably continue to go up, I would think. That's just the nature of the business. I always say the operators take the day rates up, not the contractors, because they (indiscernible) for rigs.

Last part of the question -- when you look at bringing these rigs back, Nabors mentioned that the cost of bringing them back is increasing. Is that what you're seeing? Can you give some sense of how much it is costing you to bring these additional rigs back on?

I think that giving an estimate -- when you say each rig -- is more misleading than helpful. And the reason is because, as Cloyce said just a minute ago, some rigs go out relatively little expense, some others we've put some major dollars into. It really depends on where the rig is going and the circumstances it's going to work in. So the numbers vary so much that I'm reluctant to put an average on it, because I don't think it tells very much by way of information.

Is there a trend there? Are we seeing it go up, or is it just really more one-off type things?

There is clearly a trend in the fact that steel is more expensive, demand for equipment is greater, so sure there's pricing pressures on the supply of parts that we are buying. That's clearly reflected throughout the industry, and we understand that and accept it. But more than that, I'd be reluctant to try to quantify it. John, Cloyce anybody want to --

I think that the rigs, for example, the rig we just sent to the Rockies, we spend less than a half-million dollars -- around a half-million dollars, was it? -- on that rate rig. To put a boiler and all and send it to the Rockies to work. And we've spent as much as $4 million on a bigger rig and had to buy equipment. But it's the circumstances you're sending the rig and it has a lot to do with the price that you're getting for the rig too. In other words, your day rate will be commensurate with what we spend on it, or we are not going to bring it out.

You know, we have a variety of rigs in varying conditions. If you look at the real big picture year-to-date, as Mark mentioned earlier, we averaged 197 rigs working in the first quarter. We've seen rig counts in the mid 230s here recently; that's about 40 more rigs. And if you look at what we spent on bringing rigs back year-to-date, our number's about $20 million. On that basis, it's a half a million a rig. That consist of, as Cloyce pointed out, some rigs that are very ready to run, combined with others that haven't been run more recently that we spend a little more money. We're picking from all those rigs to work toward, over a longer period of time, higher and higher utilization of our total fleet.

That's very helpful, thanks.

James Wicklund, Bank of America Securities.

Easy for you to say. Guys, I guess to drill down a little bit --

Jim, we can barely hear you. Can you speak a little closer to the receiver?

Can you hear me now?

Now we can hear you better.

Last quarter -- and it's a follow-on to Marshall's. Last quarter you were upgrading five rigs for an average price of 2.5 million, and I understand averages are difficult and it depends on where they are going and what day rate you're getting. That kind of begs the question, what is the day rate differential by region? Are you getting a significantly different day rate for rigs in the Rockies versus rigs in East Texas? Can you talk a little bit about -- I guess this is directed to you too, Glenn. Can you talk about what types of rigs or what's different on the rigs by region that changes that day rate?

Actually, what we are seeing right now, Jim, is that the day rates are going up in all regions. Even in the South Texas and East Texas area, the day rates are probably getting equal to what they are in the Rockies. Because rigs were flowing out of this area into the Rockies because of higher day rates in the Rockies. But what we are seeing now, the day rates are going up in this area, so there's not going to be the demand of pull the rigs out of this area to go to the Rockies, from our prospectively, you know, because of the economics. And I can't tell you that there is a real differential in day rates in areas right now. They're getting pretty good in all areas.

Well, help me with this. You've got one rig that you can put to work for half-million bucks and one rig that you can put to work for 4 million bucks. Wouldn't you be putting more of the rigs that only cost a half-million bucks to work?

It depends on what the people are asking for. And the rig for half-million bucks was a smaller rig -- Glenn, what horsepower was that rig? Was it 800 horsepower? It was an 800 horsepower rig, had a smaller derrick on it, and the rigs that we are spending the large amounts on -- and by the way, that rig had worked this year, I think. It worked this year, and we just refitted it to go to the Rockies. And the rigs that we were talking about last time, the 2.5 million bucks, had not worked in years; never had worked for us. It was rigs that we had bought and had stacked and had to completely rebuild those rigs. That's the difference in the two. Most of the rigs that we have in our fleet that have run will not take the $2.5 million, or the average, fix up.

And I assume that the sweet spot is still in the 1000 horsepower range?

It's still in there. We're actually seeing some smaller horsepower rigs going back to work, and I think it has a lot to do with oil. The oil price, and we're seeing a demand for oil rigs now. And I think if these oil prices stay anywhere close to where they are, or even $40 or better, you're going to see more oil rigs working than we've seen in a while, I think.

If we're looking at lower horsepower rigs and drilling for oil, this company that people are talking about that's building the 600 horsepower new rigs that can drill 8, 9000 feet, does that pose a real -- is that a real rig that can work? Will people actually order those and use those?

Jim, I don't know. I'm not familiar with that. I heard it down here for the first time. We've not been approach by those people. My experience is that when you get a rig all in, it's usually more than what you hear the price per rig is, because it takes a lot to rig up, and the way the people want it to, where you can move competitively. I don't know about this rig, though, that you are talking about, and I don't know about their manufacturing capabilities and how many rigs they can put out and what period of time. You know, to build 20, 30 rigs, yes, it's a percentage. But the rate that demand is going up right now, it's not much of a percentage of the total fleet.

They say they can build them with a top drive for 5 million bucks and they got orders for over 10, but we'll see. Last question if I could, on acceleration and day rates. We are all talking about how day rates are hitting the inflection point. Not to really have you talk about competitors, but there seems to be a big difference between your margin increase sequentially and some of your competitors.

I think that's pretty obvious, and I think if you've listened to our last conference call, we've talked about it over and over again, that people were behind us on both utilization and day rates and margins. At this point they're finally catching up, and I think that as we go forward, we can all move together.

Scott Gill, Simmons & Co.

I've got an operational question for you, Cloyce. The Permian Basin, what are you seeing in that part of the country with respect to outlook for activity improvements into '05? We've seen some property transactions on the E&P side, and is that manifesting itself into some rig demand growth?

We've never seen any time when the properties traded hands, so far, that it didn't increase the demand for rigs. We are seeing an increase in demand for rigs in the Permian, both oil and gas rigs. And we would anticipate that, as these properties change hands, that we'll have greater demand for our rigs.

Could you maybe quantify for us what that might mean in 2005? Could the Permian drive another 20 rigs for Patterson? Or is it something smaller than that or something bigger than that?

I would think it would probably be smaller than that, because the demand for our equipment is so great in all areas that we would not put it all in the Permian. We have a lot of rigs in the Permian now. Actually, day rates are somewhat better in other areas, and as long as the day rates are better in the other areas, we'll probably continue to put out rigs in the areas that are most economic for our company.

Another operational question here -- you mentioned wet weather in early October. What geographic regions was that impacting?

It's impacting mostly in the Permian. it's unbelievable the amount of rain we've had -- we'll give you Sutton County, for example. We've been shut down where we couldn't move rigs there eight times this year. And that's almost unheard of. Usually it doesn't rain hardly but once a year there in that area. You know, it's short-term and -- New Mexico, we had a lot of rain there. I think we've been affected -- Glenn, wouldn't you say we've been affected more in the Permian in October than we were in South Texas? Yes, it's more in the Permian where we were affected.

Lastly, if you can give some kind of commentary on drill pipe requirements. Where do you stand today with respect to your inventory of pipe? And how much incremental pipe were you going to need going forward? And just what you're seeing in terms of price increases --

To give you an idea on pipe, we kind of use a five-year average on (indiscernible) string of pipe, and 10,000 feet per rig just as an average. We need about 500,000 feet a year on an average basis. We still have a couple hundred thousand feet. We bought -- how much of that 5-inch did we buy? Was that 100,000 feet that we bought? We bought 100,000 feet last quarter. If you remember, we had capital expenditures for that. Going forward, we have 1000 joints a month coming in? We've got on order right now 1000 joints month. I would suspect that would increase as the rig count increases going into 2005, we'll probably get more pipe on order. We do it on a very systematic basis where we just take so much a month.

You're not seeing any shortages or anything like that are you?

We haven't yet.

Kurt Hallead, with RBC.

Just wanted to get some clarification on the outlook on an activity level, talked about 225 average potentially for the fourth quarter. Can you give us the mix between U.S. and Canada?

In Canada, as you move toward the end of the year, we would typically run all the rigs. We have 17 rigs there now. Average for the quarter, it would probably be somewhere in the 12 to 14 range. As you know, it's greatly weather-dependent.

The other thing is, between Nabors and Precision (ph), we're getting a read on the cash margins up in Canada around 7000 a day. Are you guys seeing about the same thing up there?

Is that looking back or looking toward the winner?

That was looking for the third quarter.

I don't believe our margins were that high in that quarter.

And how about looking forward?

As you move toward winter, that can happen when you have the greater amount of equipment. As you know, in Canada you have the rate for the rig and then the various other equipment you rent with it, which in fact, enhances the overall daily margin in the winter. Last year in the first quarter -- I guess this year first calendar quarter -- we saw margins that were 5, $6000 day range. So that certainly could be true, but I don't have anything here to tell you that it would be.

You said that you were running 230 rigs last week, and you're going to average 225 for the quarter. I'm assuming that's going to be because of some of the slowdown during holiday in the U.S., is that correct?

We never know what the slowdown is going to be. Last year it was a little bigger than we anticipated. This year it may be less, commodity prices are higher. But to the 225, we're assuming there will be a reasonable, but not big, shutdown at Christmas. If it is less than that, we could average a few more figs, maybe 230.

Based on all the commentary we've heard from you and your competitors and other places in the market, how would you characterize the current market environment? Do you think it's very similar to the fourth quarter of 2000, at which point we saw a 30% increase in pricing in two quarters? How would you categorize the current environment?

I would think, certainly you could see some substantial increases. I'm not saying that it won't happen, because that's one thing we don't control really. What I've seen is a more methodical uptick, as we've gone along. We've reached an inflection point now, and I just don't know really what's going to happen and what people will demand for rigs. They actually set the rates, they call when we're on an uptrend.

So basically, current period feels much stronger than it was in late 2000? Is that a fair characterization?

I think it's different -- I've never seen the fundamentals so strong. If you remember in late 2000, early 2001, we were starting to the pressure on commodity prices roll over. We haven't seen that at all this uptick. You've read all the fundamentals on natural gas and crude oil in the world, natural gas in North America. I think it's so different than anything I've ever seen. As we go forward, I think it's a long sustained upturn, myself. That's the way I see it.

Kurt, one follow-up point. Just to get possibly the $7000 a day margin in Canada was in Canadian dollars.

Yes, that's right.

Okay, that would be accurate. I apologize, I was thinking U.S. dollars.

I appreciate the follow-up.

Matt Conlan, Weeden & Co.

Good quarter. Your depreciation was up about 10% from the second quarter to the third quarter. Is that a function of more rig days operating? Or is there something else going on?

What was the question?

Depreciation was up 10%.

Just additional capacity coming online and capital expenditures over the last number of quarters.

Okay, so the CapEx of reactivating equipment is starting to flow through depreciation?

Yes, when you say they were off, I think you have to look at the various segments. I think overall we're actually down slightly from the second to the third quarter. (multiple speakers) is a factor where we brought on 18 rigs in February.

But I have -- it shows that your depreciation was at 30.8 million this quarter, up from 27 and change last quarter.

For that purpose, I am including the E&P, which had an impairment charge in the other quarter. Yes, it's just activation of equipment. As we look to the fourth quarter, I would think that depreciation would go up about another million dollars overall, companywide.

Just as a refresher, do you depreciate your drilling rigs on a day's worked basis or straight line?

No, it is straight line.

Arun Jayaram, CSFB.

Mark, John, at current operating margins, using your Q3 margin, you're generating about 1.2 million in EBITDA per rig on a yearly basis. So I was wondering, one of your competitors, a major competitor, suggested that they're comfortable investing 3.6 million or so per rig on the reactivation. I was wondering, on a payback basis, where do you feel comfortable putting more capital in the rig on a payback basis? Is it three years, four years, assuming current margins?

That's an interesting question, we readdress it no less than quarterly. We go through a process, looking at what we're activating, how much we're spending and what margins are doing. Typically in our business, we're looking for paybacks that are three years or less. If margins get higher, we're looking for faster paybacks than that. We haven't gone to the point to say we're willing to spend 3.6 million a rig, frankly, because I don't think we believe we need to at this point in time to activate rigs. Some of the rigs are more expensive because they haven't run for longer, and others are near ready to run, and we continue to try to balance those to. And we're hopeful that at some point we can get to 361 rigs operating at very appealing margins.

We also put in capital expenses into rigs depending on what the nature of the rig is. A 2000 horsepower SCR rig we are willing to invest a greater number of dollars into. Because the asset is worth significantly more as a finished, completed, ready-to-work rig than we would some other rig. And that's the reason why I was so hesitant in the prior conversation, prior questions, to pin average numbers on rigs, because they vary so much over the fleet.

But it sounds like three years of -- a ballpark number in terms of that, what you would -- is that right?

I would say three years or less.

We look at that same sort of thinking in terms of acquisitions. And look for what the payback will be, as well as a number of other factors. But that three-year number is one which we have looked at carefully.

Second question in -- if you look at your daily operating cost on a per-rig basis, they were down, I think, $190 sequentially. Can you talk a little bit about that positive variance?

Go back to the second quarter, we were very rain-affected. You're probably tired of us talking about rain. When the industry is at higher utilization levels, you can't send the crews home. So if you have a fair amount of rain and lost days because of that, those people need to pay their bills, they are going to get paid. And that results in higher costs per day. Third quarter was a little more normal in that respect, and that helped bring our costs down. And going the other way, by the way, you have us running more rigs. When you're bringing them out, there's a little inefficiency there. But over time we should be able to see some decrease in our cost per day as we run greater numbers of rigs more stably.

And last question, would you see the prospects or possibility of some wage increases and maybe talk about where you're at in that?

We've really not seen the pressure of wage increases. We had a substantial wage increase in 2001, and then we cut rages. And we brought the wages back up to where they were. We are competitive in our economy with other industries, so I don't see that happening. It's certainly a possibility, but we have not seen it so far.

I would just say, characterizing your comments, you don't see any real pressures on the cost side, for the next couple of quarters at least?

We've had a couple of costs in this (indiscernible) a little different. We've talked about insurance many times. That is a higher cost today than it was in 2001. Even though we don't pay fuel on the drilling rigs, we do have a lot of trucks. We move rigs, we have pickup trucks that are used by many people, and gas prices are higher today. So, there have been some costs that are higher. Insurance, we fix maybe 150 a day; fuel could be 100 a day or so. But we have not seen any other things that others are not experiencing, in effect, in other businesses, unique to us.

And those costs are already costs which we have seen running through our financial statement over the last three quarters. I think your question is -- prospectively looking forward, do we see on the horizon additional costs coming about? The answers is no.

Jud Bailey, Jefferies & Company.

Most everything -- my questions are answered. But I do have a quick question on your fluid business. That business is a little more centered on the Gulf of Mexico, and we've seen a little bit of an increase in activity there, primarily on the deepwater inside. Would that help your (indiscernible) fluids business a little bit more to have an increase in deepwater drilling versus more activity on the shelf?

We do actually have a deepwater contract going right now. As the Gulf improves, our fluids business improves. We are big along the Gulf Coast, and fluids, even though we do have a large land operation, the cost of running the Gulf Coast operations is very high. And if you don't have a lot of businesses, you don't do well there. We've seen improvements in the fluids business the last couple of quarters and I would anticipate it to continue, if not improve, at least not be a drag.

More broadly, Jud, on our secondary business. Our take for the fourth quarter is that they will each perform similarly to how they did in the third quarter. Our pressure pumping business continues to be strong in Appalachia. On the other side, they do have some slowdowns in the fourth quarter, of the holidays where the oil business basically shuts down up there. Fluids, they had a nice second and third quarter, and we'd think it would operate at similar levels in the fourth quarter. The same statement on the E&P side, we think the fourth quarter would look a lot like the third.

Any sense on 2005 for pressure pumping? You've added some capacity there? On how much better that business could be next year?

We continue to add capacity, so we would expect it would continue to improve in 2005. Plus the impact of pricing increases for that segment.

(OPERATOR INSTRUCTIONS). Marshall Adkins with Raymond James.

John, could you help us with the SG&A line? That has bounced up a little bit in the last couple of quarters. What should we be modeling going forward on that?

I think similar to third quarter. What's driving that is primarily two things. One, our Board has gone away, mostly away from the stock option approach to compensating executives for restricted stock. And that's expensed currently, as you know, and that's in the numbers that you are looking at. They are in there for a full quarter for the third quarter. The other thing is, I think you'll hear more and more about, is the cost of Sarbanes-Oxley compliance. It's over $1 million of identifiable fees, in our case. And that's hitting the current quarter. So it really started to affect us a little bit in the first quarter, primarily in the second. To your specific question, roughly $8.3 million, we think, is a good go-forward rate at this time.

Great, that's helpful. Mark, I know we've talked about this a lot in prior calls, but could you give us a sense -- you guys are throwing us a lot of excess cash. I know at the Board level you all look at this all the time, but any new thoughts on where you are going to go with all that cash over the next year or so?

I think we've talked about this -- as I seem to think about it -- virtually every conference call.

Well, no one asked it yet.

The challenge to have new thoughts is a challenge I'm not sure I can meet. The same thoughts apply, which is that we think that it is one of the primary concerns for management and the Board -- is how to use the cash in the most effective way. We've historically, as you know, put the cash into the company in new acquisitions or into CapEx. We instituted, as you know coming out of the second quarter, a cash dividend as a way of indicating to the shareholders that, to the extent to which there was excess cash that we did not have an immediate need for, we would give it back. And those same thoughts, I think, really govern our behavior right now. Which is, the money will be used either for acquisitions for improving our business by spending on internal projects, such as rig refurbs, additional capacity and pressure pumping, and the like. Or finally, giving back to the shareholders in the form of dividends or otherwise. That's it.

We have no further questions at this time. Management, do you have any closing comments?

We appreciate everybody's participation, and we thank everybody for joining us on the call this morning.

Thank you. Ladies and gentlemen, this concludes the Patterson-UTI Energy third-quarter earnings conference call. If you'd like to listen to a replay of today's conference, please dial 303-590-3000 and enter the pincode 11011236. Thank you for your participation. You may now disconnect.