Patterson-UTI Energy Inc (PTEN) 2004 Q2 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Patterson-UTI Energy second 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. As a reminder this conference is being recorded today, Thursday, July 29th of 2004.

I would now like to turn the conference over to Mr. Jeff Lloyd on behalf of Patterson-UTI Energy.

Thank you very much. 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 their associated effect 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 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. Copies of these filings may be obtained by contacting the Company or the SEC.

And now it's my pleasure to turn the call over to Mark Siegel, Patterson-UTI's Chairman.

Thanks, Jeff. With me this morning is Cloyce Talbott, Chief Executive Officer of the Company; Glenn Patterson, President and Chief Operating Officer; Jon D. Nelson, Vice President and Chief Financial Officer of the Company; and John Vollmer, Senior Vice President, Corporate Development. This morning, Cloyce is going to start it off by giving our opening statement.

Thanks, Mark. Good morning and thank you for joining us today. I hope that by now all of you have had an opportunity to read our earnings release.

Before taking questions, I would like to take just a couple minutes to review briefly some of the highlights from the release and to add some context to the results.

Personally, I'm pleased to report that this past quarter we embarked on a series of actions that demonstrate our faith in the Company's ability to meet current and future financial obligations, and continue our strategy of growth through selective acquisitions while allowing to us to return some of our earnings to our shareholders.

On June 2, 2004, we paid our first cash dividend, and on June 30 of '04 our 2 for 1 stock dividend became effective. In addition, on June 7 of this year we announced that our Board of Directors had approved a stock buyback program for the purchase of up to $30 million of the Company's outstanding common shares.

Thus far, we have purchased approximately 100,000 shares at an average price of 14.82 a share in connection with this program. Also, I'd like to note that a third quarter dividend of 2 cents per share will be paid on September the 1st.

Now I'd like to briefly highlight the financial results for the quarter. Net income for three months ended June 30, 2004 increased by 61% to 19.6 million, or 12 cents per share. Revenues for the three-month period increased by 20% to 234.5 million.

Net income for the six months ended June 30, 2004 increased by 114% to 40.3 million, or 24 cents per share. Revenues for the six-month period increased by 26% to 453.3 million.

During this quarter, the Company incurred exploration and production-related impairment charges and dry hole costs in the amount of $2.5 million, or 1.6 million after tax, associated primarily with certain projects that we had ongoing in Mississippi.

The two-year trend in our land-based contract drilling business, upward trend in our -- the two year upward trend in our land-based contract drilling business continued in the second quarter. We expect this upward trend to continue well into the future, based on increasing customer demand reflecting the expectations that natural gas prices will remain high.

We, therefore, expect our rig count and day rates to continue to increase. As a result of our positive industry outlook, we increased capital expenditures during the second quarter. In addition to typical capital expenditures which maintain our equipment in good working order, we are expending significant amounts on the following.

We are activating 5 of the Company's 1000 and 2000 horsepower rigs which weren't marketable and haven't worked since their acquisition. Actually, the first 1 of those 5 went to work two days ago. We're upgrading 3 of our Canadian rigs during the down season.

And we are systematically replacing our older mud pits and raggedy (ph) circulating systems to keep our equipment in good shape and maintain it where it will be competitive in the industry.

And we're also adding the addition of iron rough necks and other safety upgrades for the Company's rigs. And we are adding capacity in our pressure pumping division.

We believe that these expenditures will allow our Company to maintain our competitive advantage and maximize our returns in the favorable oil service environment which we expect to continue.

During the second quarter of 2004, we averaged 203 rigs operating, including 198 in the U.S. and 5 in Canada, compared to an average of 183 in the U.S. and 14 in Canada in the first quarter of this year. We estimate that our rigs operating will average approximately 209 rigs in July, including 201 in the U.S. and 8 in Canada.

Our operating results for the quarter have been negatively affected by abnormally wet conditions, especially in West Texas and South Texas, which has resulted in lower rig utilization and higher operating costs per day than we had initially anticipated.

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

Operator.

Hello?

Thank you, sir. At this time we'll begin the question-and-answer session. One moment, please, for the first question. Our first question comes from James Wicklund with Banc of America Securities.

Good morning, guys, that was the shortest opening comment we've heard during earnings season. So I think your operator had taken a nap. Spending significant amounts of money to put out capacity -- can you quantify that a little bit for us Cloyce? What’s you're spending per rig, how many rigs you'll activate, that kind of stuff?

Jim, we actually are doing 5 rigs. One's already gone out, 2 of the others are going out in about 30 days, and the other 2 will go out in the next 60 to 90 days. On those rigs in this quarter we spent about $6 million on the 5 rigs. Actually we're going to spend between $2 and $2.5 million on average per rig.

Okay. And this is the first 5 of how many we're going to pull out?

We actually -- these are rigs that we have activated that we bought, you know, previously and these have never worked. And we just sense that we're going to need the additional capacity of these type of rigs.

We think that -- you know, I know you don't quite feel the way we feel. But it looks to me like this work is really expanding and we -- we can put out as many as probably 300 rigs. But we just wanted to get these 5 in the fleet.

Okay. The land rig newsletter has said that effective market fleet’s about at full utilization. And you guys and Nabors are the only ones with excess capacity. Have you done any long-range planning over, you know, the next 12 months?

In addition to these 5, how many will be behind it? And is the cost of those rigs -- I'm assuming you're doing your best rigs first. So would it be fair to assume that the capital cost of additional rigs brought out over the next 12 months would be higher than that 2, 2.5 million range?

No, Jim. This is Mark. It would absolutely not be a fair assumption to do that. These are premier rigs which the Company acquired several years ago which have not worked. And these were rigs where we did a complete upgrade of the rig to put them into the market at fleet. There's a significant number of additional rigs we think can be brought to market for relatively minimal capital.

Okay. That's great. Okay, guys, thanks.

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

Yeah, let's talk about the day rates. You were up about $215 on day rates, margins were only up 65. I'm assuming a lot of that is probably because you geared up and the rain hit you, and so margins didn't flow all the way through. Is that correct, or are you seeing costs creep outside of that issue?

Marshall, this is John. Specifically in the quarter, we think we're really rain affected. Rigs go up, rigs go down. Really the whole first six months of this year, rain has been a big factor for us.

There is, on the cost side, we've mentioned before insurance costs are higher and what not. But specifically with the rain going on, the industry's getting comparatively tight on labor compared to where it was about a year ago.

You really can't send the crews home, you know, they need to get a paycheck and feed their family. So, when you get periods where the rigs go up and down this frequently, that creates cost inefficiency. And we think that's what’s driving the 72, 75 cost per day versus the 71, 25 in the prior quarter.

If the rain doesn't continue, we'd expect that to pull back some in the third quarter, you know, maybe 7200 type level. And, you know, as we get more rigs running as quarters go by, if that continues as we think it will, then the cost should, you know, continue to come down some from there.

Marshall, there's also a little bit of compression in margins because of the mix with Canada, of course, being slower in second quarter. That has an impact on, in effect, blended margin.

Right. That makes sense. All right, most of the guys we've talked to recently said we're seeing generally across the board an acceleration in day rates, depending regionally where you are, but generally the last month or two an acceleration at rate increase. Is that what you're seeing? Can you give us a kind of a rough sense of the order of magnitude there?

I think it's -- Marshall, that's one of the things that makes me so bullish on the market right now, is we are starting to see day rate increases and there (sic) are accelerating more than they have in the past. And, again, it's in certain markets.

But we're seeing demand for rigs that I haven't seen in a long, long time, and I'm pretty excited about it, as you can tell. But I think that day rates are going to continue to increase as the demand goes up.

And what I think is going to happen towards the end of the year, you know, we always have this year-end drilling. And I think the demand for drilling rigs, where it is right now and ability for to us supply them, is going to be a real shortage of rigs in the end of the third quarter and into the fourth quarter. That's what I see.

But is that translating right now to, you know, an acceleration of rate increase?

I think it probably is. I think we're kind of in that mode right now. And who knows what's going to happen, but, you know, we've got to look out for our shareholders the best we can and get as much money as we can.

Sure. That's kind of what I figured. Mark, you mentioned that you have quite a few rigs in inventory you could bring out at relatively low cost other than these 5 higher cost ones. Can you give me a sense how many that is that would require fairly minimal investment to get back to work if you had the people, et cetera?

Marshall what we think is that we can run approximately 300 rigs at relatively modest cost in terms of incremental Cap Ex to put that incremental number of rigs to work. As you might guess when you're averaging 210, you're having more than 210 rigs actually working, sizably more than that actually, because some rigs drop off and others start up in the quarter, particularly in periods of time in which there's been as much inclement weather as there has been.

So we're actually operating significantly higher than the average number of rigs right now that is listed. And we're saying that we think that there's a sizable number of rigs on top of that that can come back in at relatively modest capital expenditures.

The thought in this case was that these 5 rigs, which were acquired by Patterson quite a long while ago, are rigs that there's an extremely high demand for at this time. And we wanted to put them back into the marketed part of the fleet.

Makes sense. Last question. 50 million of Cap Ex, is that the run rate, John, we ought to plug in going forward? Or is that going to come back down?

We think for third quarter it's going to be similar. Some of these programs are ongoing, as Cloyce mentioned, activating the 5 rigs, some of those expenditures are in the second quarter, some will be in the third. With the mud pits, that program will continue in the third quarter, so our guess would be a similar rate to the third quarter.

In fourth quarter, you know, it's a little farther out from here and a little harder to gauge. If activity continues to increase in the industry, and we continue with the same programs including, you know, activating some of the, you know, nonmarketable, never been marketable rigs, then you could see a similar level. If things are at a more -- at a slower rate, then I would expect capital expenditures would drop in the fourth quarter.

I don't think they're going to slow. Thanks, guys.

Thank you. Our next question comes from Arun Jayaram with Credit Suisse First Boston. Please go ahead with your question.

Good morning. Cloyce, I was wondering if you could comment on where some of the leading edge rates are for your rigs. And how would that compare to the roughly 10.2 that you did in the current quarter? Are you some seeing acceleration above that rate?

We have some rigs that are above that rate. But it's usually -- I'd say that our leading edge is in the 10.5 to 11 range. Most of them are back in around the range of what you see in our report.

Let me make a clarification. I think it's useful. Oftentimes people speak about leading day rates. And what we're giving in our press release, of course, and all these other things, is an average rental -- average daily rate which includes a number of other charges that we -- that are part of it, including mobilization and other things.

So it -- once -- one should be careful about using those two numbers interchangeably, and I just want to make sure that we don't do that. Cloyce's answer stands as to day rates. But it's not necessarily the same as the number we report for average daily number.

Okay. Cloyce, the genesis of the question was, Nabors had indicated they thought that their margins would be up, you know, between $400 and 500 sequentially. And given that you have about a month of history, I was just trying to get a sense of where you thought your margins could increase as things play out as would you anticipate.

I think our best guess at this point in time would be on a margin basis, including factoring in cost changes and rates and can -- that being an increasing component of our rig count in the third and fourth quarter, that we would -- we think we'll see somewhere around $400 a quarter increase.

In other words, third quarter is somewhere in the $3300 a day margin and $3700 in the fourth quarter. Now, if rates continue to accelerate, that could be better. But at this point, that's our guess.

That's helpful. Last question. Cloyce, could you comment on how you're doing in the Barnett? There's been a lot of E & P companies talking about that play moving towards more directional drilling and more horizontal drilling. Has that impacted you, given the mix of your asset base in the Barnett?

No, we actually have 25 rigs running in the Barnett Shale. We're increasing that as we speak. People are requesting more rigs and we're going to be putting more rigs into that area.

It's really a matter of being very efficient, and when you go down there you've got to be real careful. If you put too many rigs in there too quickly, you don't get the labor and you become inefficient. And it destroys your reputation as well as the profit margin you make when you're not efficient.

So we're slowly moving rigs into the area. We have plenty of rigs to put in there and they are requesting larger rigs in the 750 to 1000-horsepower range, they're wanting Triplex pumps. And most of the work is headed towards horizontal.

But we're able to accommodate our customers. When we do accommodate them, though, we want to be very efficient with it. We don't want to go down there and get a black eye by not doing a good job.

So you're saying that the shift is not really hurting you guys at all.

No, not at all.

Okay. Thanks.

Our next question comes from Scott Gill with Simons and Company. Please go ahead with your question.

Yes, good morning. Cloyce, you talked about reactivating these 5 rigs. It sounds as if they are going to work on contracts. Can you talk a little bit about what those contracts are for these 5 rigs?

We just don't have long-term contracts. We're actually sending them out just like in our regular fleet, Scott. We do work some months for companies at the same rates, but they can stop or we can stop on any given day. So they're going into the marketplace.

Actually, one of them is going to Wyoming, and one started here in South Texas. And the next one, it goes out -- I think it's probably going to go to East Texas. So it'll just go into the areas where we're working. And we're literally going to send them to the areas where the demand is the greatest right now.

I think the impression you got, Scott, is just based on the fact that there's a fair amount of customer demand, as Cloyce spoke to. And people are wanting to get in line to grab a rig as soon as they can see one available.

Okay. Just another question, you're looking at the rig count. I understand the rain delays associated with the second quarter. It was very wet in Texas. The month of July surprised me a little bit from the standpoint -- I thought the U.S. would have shown a greater increase from the Q2 average, up only 3 rigs here in July.

Can you talk a little bit about maybe what the exit rate in July is in the U.S., and what you see over the next week or two in terms of where the U.S. rig count could go?

Scott, that average is continue to being affected by rain, frankly. We've had much higher rig counts at points in time during the month. So I think the fundamental demand is higher than what that average is showing.

You know, on the other hand, internally we're putting rigs out carefully. Want to do it, as Cloyce mentioned, I think the one thing Patterson does is continue to try to provide top quality service as it puts rigs out. Our guess for third quarter is that we'll average somewhere toward 205 in the U.S. and 10 in Canada.

And, you know, in the fourth quarter we, you know, see a total average closer to 225 with, you know, a little bit of growth in Canada, somewhere between 10 and 15 rigs averaging, and the remaining increase coming in the U.S., putting us somewhere between 210 and 215 in the fourth quarter in the U.S.

Just anecdotally, today we have 8 rigs down for rain. If you see the Texas news you'll know that I-20 outside of Fort Worth is underwater. We hate to keep explaining rain. It's been a unique rain year. And what we're really trying to, I guess, to get across is the fundamental demand is good and continues to increase

And given all the rain, we were actually pleased with the increase in the second quarter on our U.S. rig count. That's a substantial increase. And we expect it to continue to increase through this year.

John, I guess my final question, I don't know if you can do this number. But if we're to take the cash margins in the second quarter of, let's call it $2900, if you were to back out the cost associated with the rain delays and rig moves and all that stuff and had a normalized cash margin, what do you think that number would be for the second quarter?

You know, we've tried to get our arms around that number a couple of times. And, you know, we haven't come up with anything we felt was highly credible. I'll start out with that. As you know, there's (sic) a lot of assumptions you end up making.

You know, my belief is that it may have impacted costs, you know, 100 to 200 a day. But, frankly, Scott, that's a guesstimate. I'm attempting to answer your question. But I think until we get a more normal period, I cannot get a perfect handle on that. Just too many moving parts.

There are a lot of moving parts on the cost side and on the day rate side Any ballpark number as to if you marked to market all your rigs today and normalized for these costs, would cash margins look more like $3500 or $4,000 a day? Any idea what that number would be, John?

In effect, the leading margin, Scott, is what you're asking for?

That's a good way of putting it, Mark.

I don't think I have an answer to that question. Leading margins --.

The hard thing about the answer, Scott, is that we've got rigs that generate very, very, very substantial margins because we operate them very efficiently. And so, it may be that the rig that has the leading margin doesn't have the leading day rate.

And so we have a lot of data that we could look at. But I'm not so sure that the data gives the answer that you're --I mean, I understand the question, it's a perfectly reasonable question. I just don't think that the data that we have is particularly responsive to it, if that makes any sense.

That's fair. Just trying to gauge your guidance on cash margins, you know, how conservative or liberal they are. Thank you.

Thank you. Our next question comes from Kurt Hallead with RBC.

Good morning, gentlemen.

Hey, Kurt.

Just wanted to clarify a couple things. John, you talked about -- you outlined some data points with respect to cash margin for third and fourth quarter, $3300 a day, $3700 a day, I think, were the two numbers you outlined. Was that for the combined U.S. Canada business? Or was that just U.S. specific?

Combined.

Combined. Okay. All right. And so second question I have for you, I look at your depreciation and your G&A, at least relative to our estimate in the quarter we're little bit higher than we had been forecasting. Can you give us some general sense on what we should expect on a go forward basis?

On the G&A side, as I'm sure everyone listening is aware, a variety of companies are looking at that the way they compensate executives relative from an accounting pronouncement. And, you know, we're no exception.

There's been a movement by the part of our compensation committee and Board away from stock option grants toward restricted stock. The accounting for that is a bit different, and it's in the G&A line.

In effect, that changed -- the expense cost of that on a quarterly basis is about $0.5 million. And that's a meaningful portion of the increase that you saw for the quarter.

The other factor which I think you'll start hearing more about is the incremental costs from basically Sarbanes-Oxley. In our case we think that's about $0.25 million a quarter. And that's, frankly, not the total cost. We've been incurring that for a couple of years now. That's the new incremental cost associated with the various certifications and things that we have to do to comply.

So between those two, about $0.75 million a quarter increase, some miscellaneous other increases and we think G&A will have a run rate somewhere between, you know, 7 million -- 7 and 7.9 million. For the next couple of quarters I'd probably use the 7.9, and hopefully we can do better. But it's basically driven by those two items.

Now, a benefit that would occur over time is, you know, option grants will have less impact on weighted average shares over time. So as this works itself out, the impact of restricted stock I don't think is any more than what options were historically. They will be less.

So SG&A 7.9 for the rest of the year per quarter. What about depreciation?

Yeah, on the depreciation line, you know, I think, you know, you're getting some impact from the increased E & P. And I would probably move toward, you know, somewhere around the $30 million a quarter number.

30 million a quarter. Okay. Now, last follow-up here. Talk about drilling fluids and pressure pumping -- very solid quarters for both of those businesses. We're hearing more and more about price increases, especially on the pressure pumping side of the business. What do you think we should expect there in terms of margins for both pressure pumping and drilling fluids as we move forward, vis-a-vis the second quarter?

In the case -- I'll start with the smaller of the two. For our drilling fluids business, I would stay with what we've been running. You know, I think if you look at us historically over time we don't do a lot better than the 15% type margin. We tend to run that 14, 15% range. So internally that's the way we would look at it.

On the pressure pumping side, you know, our margins between the first and second quarter were really pretty darn similar. A lot of activity from the capacity that's been added over the last several years, and we would expect that to -- we would expect to continue to benefit in the third quarter and fourth quarter relative to that, and, you know, guessing that jobs could well be around 2,000 mark.

Our pressure pumping business continues to kind of hit new historical highs as this up-trend has continued. I think we would expect to see a little bit of margin expansion in that, maybe up to 45%. But I don't think I'd go a whole lot higher than that if I were you.

You did address -- you did address in terms of whether some difficulties in trying to asset the impact of it. You did put forth your estimate for July rig days. Any guess as to whether or not the weather you just mentioned up in Dallas is going to have any impact on that July number?

No, I would -- when we put that July number out with a couple of days to go, rounding could get you. But the month is pretty well set at this point, I would think.

All right. Thanks.

Thank you. Our next question comes from Kevin Simpson with Miller Tabak. Please go ahead with your question.

Thanks and good morning.

Hey, Kevin.

Just following up on pressure pumping, Cloyce, did you say how much capacity you're adding and how long it will take to get in the field? And I guess are you pretty much flat out right now?

I'm sorry?

And are you running flat out there right now?

We're still adding capacity. We're running flat out with what we have. But we've been adding capacity and we are continuing to add capacity this year. We've spent $10 million on capital expenditures of the first six months and we have budgeted for the rest of the year about 8 million. So we'll be adding additional capacity.

A lot of it depends on how quickly the manufacturer can get the equipment to the guys. There's kind of a bottleneck there. But for the last two years we've been adding capacity just about the same clip. Maybe a little faster this year.

Is 20% reasonable? Or is that too much in terms of, you know, kind view on an annual basis -- incremental capacity?

20% might be a little bit high. What do you all think?

You know, Kevin, the hard part about why we're shaking our head in terms of trying to give you an answer the way you're asking the question is because what has typically been happening is that, and if you look at the map that we present typically of where our pressure pumping has been, the area in which it's operating has consistently been increasing.

So what is happening is we, in effect, step out into ever wider circles kind of out of our Meadville headquarters. That's really what's going on. We don't think about it in terms particularly of per se capacity in any one per place as much as we stepped into Tennessee or Kentucky or that kind of thing.

Okay. I was just trying to get some help on how much to juice the top line.

Kevin, if you go -- we give a fair amount of detail with our press releases. And if we just look at the current quarter we had a little over 1500 jobs. And if we go to the same period last year, which was also a nice period, it was about 1250 jobs. You know, that right there is approaching a 25% increase in the amount of jobs we're able to accomplish.

There's mix between fracking, cementing, a variety of things. But, you know, for the 12 months, either use of capacity or added capacity has been worth about 25%, and us continuing to grow that somewhere between 15 and 25% I would think is reasonable.

Okay. And --.

I'm comfortable with that answer.

Okay, good. Thanks for the clarification. And on the -- on the rig side, the rate of change, you know, I know weather is a factor, but the rate of change of your, you know, land rig count has -- your U.S. count, has been pretty consistently less than I was expecting. Maybe I've been just too bullish, but it does look like brand X has grown -- has kind of caught up and is growing a little bit faster than you are.

I just kind of wondered what your take on that is. And do you think -- sounds like, Cloyce, you're very optimistic that we should start to see an acceleration for sequential growth for the P-10 rig count, over the next -- as we see those monthly numbers roll in, August, September, October time frame.

Kevin, before we respond to that I'd like to add a little more historical fact. I think if you go look at 2002 and early 2003, brand P outstripped everybody in terms of rig growth. And if you go back 12 or 15 months we were very clear in acknowledging that we weren't going to have 300 rigs running with brand X running 100 to 120.

We got our rigs out there quickly. Glen and his people did an awesome job of doing that. But when that happens, competitors are going to hold their pricing down to get rigs out, and that's what's occurred.

We hear the noise of other people indicating now that they're more focused on pricing. And we're pleased to hear that, because we expect that means that they, like us, wish to get a reasonable return on our investments and our capital expenditures. So more recently their percentage growth of others has been higher, and --.

And I think the demand there, in fact, the demand is as -- about as great right now as I've seen it in a long time for, you know, increase in rig count.

We're -- what we're being very careful with is making sure when we put a rig out there it's efficient not only for our customer but for us, because that's a double-edged sword. You send a rig out there that does a poor job and the customer doesn't want to pay for it. And Glen's been very prudent in putting the rigs out, and we might accelerate that some.

But we had 15 more rigs working in the U.S. this quarter versus last quarter. And that doesn't sound like much, but when you start trying to find hands and run them efficiently and move them around the countryside that's quite a few rigs. That's five a month, average. So, you know, I -- I would think we'd anticipate doing the same thing.

To be fair did you roll in the Timber Sharp rig.

That's true, we did. And some of them, their rig count went down, some of them, when we took them over. And -- but we did roll those in, and that's part of it.

So I shouldn't necessarily look --.

I would say five or six, on average, is Timber Sharp.

And -- okay. But a rate of -- and maybe this expansion of, you know, the available -- taking the 5 rigs and bringing them in, is that a little bit indicative of what you see as a, you know, kind of a demand increase going forward?

It's indicative. I think the demand increase is there, Kevin. Those are -- actually, there's 4 of those rigs are 1000 horsepower, one of them is a 2000-horsepower rig. And we're seeing a real demand for the 1000-horsepower rigs in almost every market. Doesn't matter whether it's Barnett Shale or East Texas, the Rockies, that's the demand right now. So we are getting those rigs out.

Kevin, it just seems worth adding that something which I know you know and I'm sure most of the people on the call know, but it just bears repeating that, you know, $100 in margin is equal to 5 additional rigs, roughly speaking. And so we'd far prefer to see rates go up than rigs go up if we had to choose between them.

And so from a vantage point of returns to shareholders, we would both -- we would all like to see, obviously, greater number of rigs and greater margin. But what we've emphasized, I think rightly so, is making sure that we get the appropriate margin.

The, you know, basically your mantra for, you know, since you put the two companies together. Sure, that's it for me. Thank you.

Thank you. Our next question comes from Neal Mcatee with Morgan Keegan, please, go ahead with your question.

Good morning, guys.

Hey, Neal.

You know, we – everybody’s focused how many rigs you could get up and running from an equipment standpoint. How many rigs do you think you get up and running from a crew standpoint? Is that the bigger hindrance?

It's certainly a hindrance, Neal. And, you know, what we've noticed is seems like every time we've put a rig out and it's -- we get the crews eventually for it. And I think if you put -- for example, we could probably put another 6 or 8 rigs in the Barnett Shale overnight. But we could not crew those -- if we moved 6 rigs down there overnight, we would be very inefficient, and the customers don't like that. So we're being very careful as we move forward.

Now, one advantage that we have is that we've been working now for almost 18 months with a high rig count. And you've been following these companies a long, long time. You know we used to go straight up or straight down. And this flat with an upward trend rig count has really been helpful.

And this has gone on for two years now. And it looks like, from what we're seeing, it could go on for quite some time where you have a high rig count. And it helps us train employees. And we can move some from one rig to the other in areas, and like we have the 25 rigs that are in the Barnett Shale. That gives you a bigger pool to draw from.

So it just takes time. And I think we've probably been more patient this time than in the past trying to get the rigs back out, so we can be more efficient. Our customers don't like for us to be inefficient. We just put a rig out there and you take too many days, they get real unhappy.

Let me ask this. What's the, you know, the demand for higher horsepower for the Drexel drilling, Barnett Shale and all that (technical difficulty). I know in general, everybody thinks rigs are fully utilized. Are we headed to a situation, though, where we might have a dual market where 1,000 horsepower and higher could see faster acceleration of day rates than maybe the smaller rigs?

I don't know, they tend -- what we've seen in the past, they pretty much all tend to go together. We've seen that both going up and down. You know, the 2,000 horsepower rig sometimes draw a little bit more when there's a good market. When it's a bad market they all work about the same price.

Which means that the lower horsepower rig is going to have a higher margin.

Right. I don't know if Glen is still there. He feels left out. Everybody else has asked what day rates are doing. Glen, I assume you wouldn't be spending money on rigs if you didn't think day rates were getting ready to go up. Is that a fair statement?

He's asking you.

Go ahead, Glen.

Well, he thinks it's a fair statement. He's sitting here --.

All right, thanks, guys.

Thank you. Our next question comes from Bo McKenzie with Sterne Agee, please go ahead with your question.

Hey guys. A couple questions relative to reactivations. I think you said you were reactivating five 2000-horsepower rigs?

No, that's correct. 1000 to 2000 range.

Yes, I can’t write and listen at the same time for some reason. Let me skip past that one and go to the second one. I think you said 2 to $2.5 million a rig looking forward on future reactivations. Is that correct?

Specifically on those, Bo -- this is -- I'll give you an example just in -- among the rigs, 3 of those 5 rigs are from the Odin acquisition that was in, I believe, early 2002. They were not marketable when purchased, you know, in the middle or higher horsepower area. At the time it did not make sense to activate those rigs. There was no demand for them.

That demand has built over time, as you've heard from us here and on other calls. And, therefore, our operations people felt it was time to have those prepared and ready to go when pricing justified putting them out. And as Cloyce mentioned, some of them are already out. That was specific to that group of rigs.

There's a couple of kind of rig activations that we have. You know, we have a marketable fleet, and a nonmarketable fleet. And, you know, we've been pretty clear about what those are. This was 5 rigs from the nonmarketable fleet.

That is a higher investment. In this case, you know. $2.1 million a rig is what we're showing at this point, to activate those. We also have marketable rigs that we aren't marketing. They've run since we've owned them, or I should say they ran in 2001 or later, either owned by us or someone else.

That group of rigs has a much smaller investment. In some cases it's just the old rope, soap, and dope. In some cases it might be something a little more than that. And that group, I think references were made in the call to -- right now we feel without big investment we could run about 300 rigs.

I guess, what I'm trying to do is to back into what you guys must envision with the kind of day rate or margin scenario, if you're looking at something approaching $2 million a rig in reactivations.

What kind of payback period, what kind of return -- I'm trying to figure out what kind of margin makes sense, given the short-term contract nature of the land drilling markets, to spend 2, 2.1, 2.5, whatever those numbers shake out to be, on reactivating equipment. Are you looking at potential where you could see 6, $7,000 margins on the way somewhere before long for that class of rig?

Let me clarify kind of a different point. If we spent $2 million reactivating these rigs on a per-rig basis and depending which rig we paid a million to, you know, 2.5, 3 million for the original components that are being put into play here, and that would be the range amongst these 5 rigs, in one case, you know, you've got yourself a 2,000 horsepower rig, you got 3 million in and it's ready to go. Those are very different numbers than I think what you're inferring.

I'm looking at incremental investment to incremental return, frankly, you know. If I put 2 million in, what kind of period is it going to take for me to recover that incremental 2 million of investment in the equipment and what does that imply about the direction rates might be moving?

Right. You know, Bo, we don't know, our crystal ball is not highly clear here. But we know that we saw margins for a period of time that were in excess of 4,000 and in some cases ranging up to 8,000 in 2001.

This upturn continues to, you know, have strength we believe at a steady upward pace. And if you get, you know, a period of time where any given rig is generating 4 or 5 or $6,000 a day margins, that investment gets paid back I think you'd find, pretty quickly. We're anticipating the demand for this equipment is going to continue to increase.

We're not the only people that feel that. I know Nabors has made references to them activating some similar equipment. We didn't know that when we decided to do it. But the demand is there at least in the case of the top two players in the lower 48 drilling.

All right. Then geographically, you know, a number of people have commented about the change in the rig count this year versus last year. On the West Texas market specifically, it seems like there's been a reasonable amount of property turnover out there.

Are you guys hearing things from your customers that maybe that property turnover has abated a little bit, and that as we look into the second half that their programs might be accelerating? Or is there still a fair amount of money going away from the drill bit into the acquisition market?

What we're hearing out there, Bo, is that the people that have bought, for example, Magnum Hunter bought the -- EnCana properties and they're increasing their rig count.

Any idea how much they are going to be increasing going into the second half?

Do not know.

And, I guess, my last geographical question is, you know, the Rockies have continued to be an incredibly strong market this year. I think I heard, and like I said, I apologize, I can't write and listen at the same time very well. But I think I heard you guys talk about taking at least one of the rigs that you reactivated up to the Rockies.

How much more incremental demand is there before you kind of go into the seasonal downturn, that you tend to get up in the Rockies? Is it something that strategically you guys have got some parameters you're looking for to maybe make it at bigger presence for Patterson into '05?

Certainly we're looking to make a bigger presence in '05. Actually we didn't see that seasonal turn-down. Historically what the seasonal turn down is that drop in gas price, and the gas price, it is my understanding, didn't go below $4 this last summer up there.

I would -- I would think, unless they get so much gas they can't get it out of the pipelines, and, you know, they're adding additional pipelines as we speak to that marketplace up there, as long as they get the pipelines to get the gas out of there I think you're going to see the seasonality of that play disappear.

I guess I was specifically speaking to kind of drilling up on the mesas, where, as I understand it, there is kind of a regulated downturn in the winter months.

You have that. But usually the rigs move into other areas. There's lots of places, like Pinedale, you've got to move out in the wintertime and go back in the spring.

So, can you give us an idea of where you'd like to be by this time next year in terms of Patterson's fleet in the Rockies? And what it would take to, in terms of margins or contracts, to get there?

Well, certainly I think the margins are approaching -- we're moving rigs there now so we wouldn't be moving if we didn't think the margins were good enough.

We have 19 rigs in the Rockies now. Year and a half, two years ago we had 5. So you can see that we're -- and we're constantly looking for acquisitions. We missed an acquisition up there recently that we didn't want to pay as much as somebody else wanted to pay for it. And we're in the process of moving additional equipment up there as you heard.

And I would say that a year from now we would probably have another 10 or 12 rigs in that marketplace. So we'll be up in the 30-rig market and who knows where it's going to go. I think that's going to be an area, as long as we're short of natural gas in the United States, it's going to continue to grow.

I guess, then, finalizing it and let somebody else ask questions is, if you look around geographically we've heard strong things out of East Texas, the mid-continent, the Rockies and so forth, South Texas even recently, what do you guys hear in terms of the Gulf Coast? Is the Gulf Coast kind of tied into what's going offshore? Or do you see invisible signs that some supply contracts -- you could be putting some rate pressure in that market yet?

We're seeing South Texas improve from what it was or has been in the last year, year and a half. Certainly East Texas, Barnett Shale and the Rockies are the most active markets right now as far as needing more additional equipment. But we're seeing our request for rigs increase in South Texas, which is a pleasant surprise.

Higher horsepower?

About the same. Maybe a little bit on the larger horsepower, but we're working all of our 1000, 1500-horsepower rigs in South Texas right now.

All right guys. Well, thanks a lot.

Thanks Bo.

Thank you. My next question comes from Waqar Syed, Petrie Parkman. Please go ahead with your question.

Yeah, now, you mentioned that you have -- you can bring in other 80 rigs or so that you have marketable. But you're -- you're not marketing them right now. And you can bring them in at minimal cost if you decided to reactivate 5, expending $2 million or so per rig.

Could you go over, again, just sort of the thought process? Are there other marketable rigs not in the right size? Why would you decide to spend money on rigs while you have some other rigs that are -- that you can bring in and at lower cost?

I think there's, you know, a rig is not a rig in the sense that they have a variety of horsepowers, as you well know. And, you know, people need different size rigs for different drilling situations. Patterson has followed a market approach of covering, you know, everything 7,000 feet and deeper. And over the last five years we've drilled probably a few things below -- shallower than 7,000 feet and we've drilled to 30.

So, we cover the whole market. We try to cover all of our customers' needs. Within that range, that's the drilling range where you can make money and get reasonable margins. You go shallower, it's not -- it's very commodity oriented.

So, within that you know, we're -- our operating people are always looking at the rigs they have available, what the customers are needing and trying to make good decisions about how they deploy capital. In this case, there has been an increasing demand.

The tighter, not that it's dramatically tighter segment, but the tighter segment of the market for a period of time has been somewhere, you know, a little -- like 900 horsepower to 1200 horsepower, and it’s referred to as 1000.

And, you know, we have some rigs in that area that we purchased in anticipation of increased demand, bought them in 2002 at good prices. Four of these rigs, I believe, were bought in 2002, those we're talking about. And, the operating people felt it was time.

These are quick decisions that -- you're talking about a rig that has not run potentially since the 80s. And, you know, you -- it takes a number of months. So if you believe that you're going to have demand for that and be able to get good returns on margins, you have to make a decision to make the investment earlier than when you necessarily need it. And that decision was made this year, therefore expanding the -- that 1000-horsepower fleet on our part.

We have other 1000-horsepower rigs that we are not fully utilizing at this time that can also be brought to market. But in effect, the operating management concluded that, you know, within 12 months we would have demand for all these rigs.

And we wanted to be prepared so we could capitalize on those, you know, higher rates, higher demand and continue to service our customers in the best way that we can, while providing good returns for shareholders.

Now, amongst your idle but marketable fleet, how many 1000-horsepower rigs do you have right now?

I don't have the number precisely here in front of me. My guess is it's about 15, but that's off the top of my head estimate.

And those, you think, could be brought in at minimal investment?

Yes.

Okay. Great. And could you also talk about the customer reaction to these current improvements in day rates? Are you seeing any push-back? Are people maybe talking about laying off rigs if -- in case day rates go up $500 or $1,000, or they're taking it lying down?

One of the things we think is true here is that our customers are really getting a great value in terms of the drilling services that we provide. We're able to accomplish their wells oftentimes in faster periods than they anticipate, and these -- what there really is, is a huge value, particularly as against the price of oil or natural gas.

And so we think that actually our customers are anticipating these rate increases, almost have been expecting it. And as long as, in effect, our competition is not emphasizing increases in utilization over increases in day rates, we think the market is poised to show some real changes in that area.

Great. Thank you very much.

Thank you. Our next question comes from Judd Bailey with Jefferies & Company. Please go ahead with your question.

Thank you. Good morning. Most of my questions have been answered. But I have one quick follow-up, and I apologize if you touched on this already.

But you mentioned for the 5 nonmarketable rigs that you're bringing out, it's going to take another 30 to 90 days to get those out in the field. What about some of your stacked markable rigs? How quickly could you bring those out in the field if you wanted, once you activate those?

That's in days. They come out real quickly.

Okay. And just to make sure --.

One clarification. In respect of the 5 rigs that we specifically made mention of, that are being, in effect, upgraded and activated, we expect that -- one, as Cloyce mentioned, is already working. We expect most of those rigs to be in the field around the end of August. So it's -- when you say 90 days, I want to make a clarification point about that.

Okay. Just one more follow-up just to make sure I heard correctly. The 5 rigs that you are activating -- did you say that the total capital spent was $6 million total, or did I hear that incorrectly?

That was in the quarter.

Yes, that's correct.

In the quarter. Okay. Sorry. All right. Great. Thanks. Bye.

Thank you. Our next question comes from Geoff Kieburtz with Smith Barney.

Thanks. Good morning. John, you kind of defined what I heard as kind of three classes of rigs at Patterson. The marketable fleet that is being marketed, the marketable fleet that's not being marketed, and then the nonmarketable fleet. Could you put a number of rigs within each one of those three categories?

Yeah, the -- we're calling the marketable -- in other words, we may not be marketing it, but it could be run -- 300 -- the number -- I haven't gone and verified here recently.

But if I take a different -- slightly different approach, I get to about 320. And that is, if you take every rig that either we or a prior owner ran 2001 or later, the number is about 320 rigs, a little more than that, which, to compare the 361, would put about, you know, a little less than 40 in the owned but not marketable category.

And since we're conservative, we're calling it about 300 that we could put to work without significant Cap Ex. The ones that we actually have run say this year -- I'm going to be guessing a little bit here. But I think it's probably 240, thereabouts, give or take 10.

Okay.

So they've run very recently. So in that sense, they're marketed. We may or may not have 240 crews, though, because in the interest of efficiency --.

No, I understand.

The operating people will move crews to rigs rather than moving rigs in periods that are not full in utilization.

Okay. That's perfectly understandable. And, if we look at the sizes of those rigs in each of those three classes, is there any really significant difference in the mix of sizes in the marketed -- the marketable and not marketed and the nonmarketable?

The nonmarketable will be some of the lower horsepower rigs.

It’s a lot higher, too, actually.

It’ll be somewhat higher, but it will be mostly -- it will be mostly --.

You know, Glen Patterson is saying about same as the rest of the fleet. My own, without -- you know, we have to go through it rig by rig, and then sort of do it. Obviously when you take 5 out of the nonmarketed, which is what we're tell you we did, we're doing, in effect that changes the mix. And so we'd have to kind of think about it.

Sure. I'm not looking for hair-splitting, just sort of --.

Geoff, my guess about it, at having looked at the list pretty carefully myself from the vantage point of that capital allocation kind of perspective, I think it's pretty representative.

Second question. Taking into account your comments earlier about different types of rigs, different rates, so on and so forth, and the other things that go into the revenue per rig day, Cloyce, could you take, say, a representative 1000-horsepower rig and just looking at the day rate, you know, what is the day rate to put that rig to work today versus this time three months ago?

Day rate today compared to the day rate on a 1000-horsepower rig three months ago?

Yeah.

It will be somewhere between $500 and $1,000 higher today than it was three months ago.

Okay. And if you were to project three months from now would you expect the increase to be greater or less than that?

That's a good question. I don't know. But I would expect that we'll see a little bit more pressure on -- upward on day rates as we approach the end of the year, you know, the year-end drilling when so many people come in and want to drill at the end of the year.

I think there's going to be a real shortage of rigs in the fourth quarter, particularly assuming commodity prices stay anywhere close to where they are right now.

I think you'll see a lot of the onesies and twosies that want really drill a lot of wells at the end of the year. And that will push day rates then (ph).

Just to dig a little bit deeper on that from some of your earlier comments, is that --that limitation almost sounds more your ability to get properly trained crews than it is the hardware itself?

I think that's a real good analysis.

There's five guys around the table shaking their head yes.

I get the picture.

But, I mean, the real point is that you can put out more equipment. The question is can you put it out so that it's good for both the customer and the shareholder.

Totally understand.

And, you know, also as Jon just added, and will continue to run so that you don't just pay the up-front costs of putting it back in the field and then shutting it down sometime shortly there after. You've got to get all those right; otherwise, you're not doing anybody any good.

Right. And the last question, a little bit more qualitative, Cloyce you've mentioned a couple times on the call this is the strongest demand environment that you've seen for awhile. Could you kind of expand a little bit and sort of compare what you're seeing as the tone of the market, your customers' behavior, their anxiety level, and so on, relative to the middle of 2001?

I don't think the anxiety is quite as high, but it's headed in that direction. And I think that we'll maybe sense some of that anxiety towards the end of the year when people are really needing rigs. But we're seeing some anxiety right now.

And in '01 were you seeing customers talking to you about rigs -- or about well programs 2 and 3 and 4 wells out? Or were they back then still talking to you about kind of the next well or the next two wells?

Well, certainly you get some of the -- some of each of those categories. And we're talking about -- people are talking to us now needing a couple or 3 rigs for a multi-well program, you know. And when you have that, you really get some continuity to what you're trying to do and keep your rigs working.

So if somebody calls you and just wants to drill one well, we -- and we do a lot of that, don't misunderstand me, and it's a very important part of our business to service those customers. But the ones that really are meaningful is when you get a customer that wants multi-wells drilled with multi-rigs. And we're seeing a lot of that right now.

Would you venture a guesstimate as to how many of your rigs that are working today are actually on some form of multi-well program?

That's a good question. I wouldn't even hazard a guess. But it's a pretty large percentage.

Great. Thanks very much.

Thank you. Gentlemen, there are no further questions at this time. Please continue.

We'd like to thank everyone for their participation in our call. We appreciate it and we look forward to speaking with you next quarter. Thanks, everybody.