Patterson-UTI Energy Inc (PTEN) 2007 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q4 2007 Patterson-UTI Energy, Inc., earnings conference call. My name is Mike. I'll be your operator today. At this time, all participants are in a listen-only mode, and we will be facilitating a question-and-answer session at the end of today's presentation. If at any time during the call you require assistance, please key star followed by the zero and an operator will be happy to assist you. As a reminder, ladies and gentlemen, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Geoff Lloyd on behalf of Patterson-UTI Energy. Sir, please proceed.

Thank you very much. Good morning. And on behalf of Patterson-UTI Energy, I would like to welcome everybody to today's conference call to discuss the results of the 3 and 12 months ended December 31, 2007. Participating in the call will be Mark Siegel, Chairman; Doug Wall, Chief Executive Officer; and John Vollmer, Chief Financial Officer.

And just a quick reminder that statements made in this conference call which statement the company's or management's intentions, beliefs, expectations or predictions for the future are forward-looking statements and 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, excess availability of land rigs, including as a result of the reactivation or construction of new land drilling rigs, adverse industry conditions, difficulty in integrating acquisitions, demand for oil and natural gas, shortages of rig equipment and availability 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, which may be obtained by contacting the company or the SEC. The company undertakes no obligation to publicly update or revise any forward-looking statements.

And now, I would like to turn the call over to Mark Siegel for some opening remarks to be followed by questions and answers. Mark?

Thanks, Geoff. 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, which was issued earlier this morning prior to the opening of the market. I would now like to review briefly the results for three and twelve months ended December 31, 2007. I will then turn the call over to Doug Wall, Patterson-UTI's President and CEO who will make some brief comments on the results of the individual operating units. As always, we will be pleased to take your questions following these remarks.

To summarize, net income for the three-month period totaled $85.1 million, or $0.55 per share, compared to $156 million, or $0.97 per share for the three months ended December 31, 2006. Revenues for the just completed quarter were $521 million, compared to $638 million for the fourth quarter of 2006. Net income for the 12 months ended December 31, 2007 totaled 435 -- pardon me -- $439 million, or $2.79 per share, compared to net income of $673 million or $4.02 per share for the 12 months of 2006. Revenues were $2.1 billion for the 12-month period ended December 31, 2007 compared to $2.5 billion for the 12 months of 2006.

I would now like to turn the call over to Doug, who will discuss our operations for the quarter and provide some highlights and additional color.

Thank you, Mark, and good morning.

I'd like to make a few brief comments on each of the operating division, and I'll start out with the drilling company. For the quarter ended December 31, 2007, the company had an average of 241 drilling rigs operating, including 231 in the U.S. and ten rigs in Canada. This compares to an average of 243 drilling rigs operating, including 234 in the U.S. and nine rigs in Canada for the third quarter. This represents the third straight quarter of relatively stable rig count with some minor changes in the mix between the U.S. and Canada. During the fourth quarter, a number of rigs were shut down for the holiday season, negatively impacting our average rig count by about two rigs. Average revenues per operating day during the fourth quarter were $19,250, compared to $19,150 in the third quarter. Average direct costs per operating day were $11,110 for the fourth quarter, compared to $10,840 for the third quarter of '07. An increase in the number of camps and boilers working in Canada during the quarter had the effect of increasing both average revenues and direct costs per operating day. Average revenues per operating day also benefited from a term contract buyout from an operator in the Rockies. Without these items, we believe our average revenue per operating day would have declined by approximately $200 compared to the third quarter. At the end of the year, we had 47 rigs working under long-term contracts of varying length. Of these term contracts, 12 are set to expire in the first quarter of this year. We do expect our customers to continue to utilize most of these rigs, but they will be at current market rates, with some up, but for the most part, down.

I'd like mention a couple of operational highlights for the quarter and for the latter half of the year. As you know, we introduced our first customized NOV IDEAL rig to the marketplace in the second half of 2007. We, as well as our customer, are extremely pleased with the performance of the rig. The rig is working for a major independent in south Texas on a multiwell program. The rig is a fast-moving, 1,500-horsepower, 18,000-foot depth capacity electric rig that incorporates a state-of-the-art EDS system, 500-ton top drives and automated pipe handling features. We have two more of these rigs, which are currently commencing operations for major independents, and we have 12 more of these rigs ready to rig up to meet incremental demand. Also during the fourth quarter, we mobilized one of our highly acclaimed walking rigs for a major independent customer in the Barnett Shale. This rig is a sister rig to the ten walking rigs we have deployed in the Rockies over the last two years. These rigs allow for multiple wells to be drilled on a pad without rigging down. The customer is extremely happy with the functionality of the rig, and has already drilled the longest horizontal well they have ever drilled in the Barnett Shale. We see great potential for this technology in a number of emerging unconventional resource plans.

Turning now to the pressure-pumping business, we had another very solid quarter from Universal Well Services. Overall revenues were up 43% over the same quarter in 2006. Revenues for the quarter were $54.1 million, and our average revenue per job increased $14,970. As is customary, winter weather and the holiday season caused revenues to be down 7% sequentially from the third quarter. Operating income for the fourth quarter was $15.2 million, up 48% from Q4 of '06. During the last three years, we have spent over $100 million on new capital equipment in this business. In 2007, we spent over $48 million, with a large amount of that directed towards upgrading our fracturing capability, where we added an additional 24 frac pumps during the year. Much of this additional horsepower came on stream late in the year, and we will continue to activate additional horsepower throughout 2008. We have continued to increase our capacity, and we are well positioned in the Appalachian market, particularly for the emerging Marcellus Shale play. We expect this additional equipment to drive significant growth in the coming years. One of the operational highlights for the quarter was the deployment of our people and equipment on one of the first high-rate horizontal nitrogen frac in the Huron Shale in Kentucky. Universal has been a market leader in pumping these large horizontal gas frac from the Appalachian, and our equipment lends itself very well to these applications.

Turning to the drilling fluid segment, we witnessed a slight improvement in our fluids business for the quarter, with revenues up almost 11% sequentially. Lack of activity in the Gulf of Mexico is still hampering our operations. And of course, it has had a negative impact on our revenues and earnings. Revenues were down 18% compared to the fourth quarter of 2006. We really don't foresee any changes in the business drivers that would kick-start this business in 2008. During 2007, we've made a number of organizational changes, which we think will help sharpen our management focus on our oil service business. In that regard during the fourth quarter, we sold our ENP operating business, but we have kept our ENP working interest. We are pleased with this transaction and a lot of other steps that we have taken to improve our operations and marketing throughout the company.

With that, I'll now turn the call back to Mark.

Thanks, Doug.

For the first quarter of 2008, we currently expect that our rig count will be similar to the fourth quarter of 2007. In the first quarter, we expect a decrease of approximately $400 per operating day in margin, which includes the impact of marking -- market pricing of rigs coming off of long-term contracts. Recently, we have seen some encouraging signs in the marketplace, and we believe that the land rig market continues to stabilize. There are a very large number of rigs, primarily competitors coming off term contracts, and it will be interesting to see the impact that they may have. We do think that for the near future, the U.S. rig count will remain in a rather narrow band. Of course, we expect that demand in Canada will fall dramatically sometime after mid-March as break-up begins. We expect the Canadian market, albeit a small market for us, will be soft for the remainder of the year.

For the drilling industry in the United States in the lower 48, land rig counts have remained at relatively high levels throughout 2007. The combination of rig new builds and reactivations over the last couple of years has caused an excess supply of rigs. We do believe, however, that the construction of additional land rigs for the domestic market has slowed significantly. We believe that there is still some demand for fit-for-purpose new rigs to enter the market. Most importantly, we believe that long-term upward trend in the number of wells drilled will continue, as it is the principal mechanism to meet demand for natural gas and to offset steep decline rates. To meet this expected increase in rig demand in the U.S., we currently have approximately 90 currently marketable land drilling rigs available to reactivate when the need arises. We have been willing to stack rigs in a systematic and disciplined manner in light of this current rig oversupply. Despite the temporary oversupply of rigs, our drilling business has remained fundamentally strong throughout 2007. We have continued to make significant investments in businesses -- in our businesses, bringing our four-year total of capital expenditures to approximately $1.8 billion, including approximately $600 million for 2007.

During this four-year period, we have significantly upgraded our drilling rig fleet, including deploying approximately 70 new and like-new rigs over the past two years. In 2008, we plan to invest approximately $500 million in our businesses, including the continuation of our rig fleet upgrades and the expansion of our pressure-pumping business in Appalachia. We are also pleased that during the same four-year period, we have returned approximately $700 million to our shareholders in the form of dividends and buy-backs. With $1.8 billion reinvested in our company's assets and approximately $700 million returned to our shareholders, our balance sheet is pristine. And as of today, we have no debt. We believe that our strong balance sheet and our commitment to invest in our businesses will continue to serve our company and its shareholders. I'm also pleased to announce today the company has declared a quarterly cash dividend of common stock of $0.12 per share to be paid on March 28, 2008 to holders of record as of March 12, 2008.

Before we open the call up to questions, we'd like to take this opportunity to express our sincere appreciation to our employees in each of our business units for their dedication and hard work. Our results would not have been possible without their efforts, and we thank them for a great year. Patterson-UTI is undergoing a dramatic transformation, and we are very excited about the future.

At this point, I'd like to open the call for questions.

Thank you, sir. (OPERATOR INSTRUCTIONS) And our first question comes from the line of Kurt Hallead with RBC Capital Markets. Please proceed.

Hey, good morning.

Good morning, Kurt.

I just wanted to -- you said, Mark, cash margin down $400 a day, first quarter versus fourth quarter. You said that you see some encouraging signs out there. Does that mean that you think that rates are going to stop declining, or do you think the decrement will be generally less than what we've seen in the fourth quarter and first quarter?

Kurt, I think that our -- it's hard to sort of -- let me break the question into two parts. The reason for the comment about the change in margin is the impact both in our company and other companies of term contracts expiring. That's the principal reason for that comment, where in effect, you have an adjustment to market from a rate that may have been set 18 months ago. So that's the principal reason that we're giving that number. What we're saying is that in the overall market, we're seeing, at current, a stabilizing of the market. That's the word we've used in our comments, so that that's how to square those two thoughts, if that makes any sense.

Okay. Does that mean that you think that after this first quarter, to come back to the core of the question, do you think that pricing is going to stop going down, or you think it's going to go down on a less decrement?

It's going down at a much smaller decrement.

Okay. And then, in terms of encouraging signs, you said there was a number of rigs coming off contract. Was that a reference to the industry in aggregate, or was that a reference specifically just to your stuff?

We've got -- we have some coming off, as we discussed or as I said in the remarks at the start, we think that the industry as a whole has a large number coming off.

Okay. And with the industry as a whole with a large number of contracts coming off, so your comments basically suggest that you don't see any of these rigs becoming increasingly more competitive with day rates, relative to where the market is now?

Well, the thought that we have is that there's sufficient demand for rigs at this point, such that we're not expecting undisciplined price competition as those rigs come off of term contracts. We think they'll go to kind of a market rate, and we think that market rate is showing a fair degree of stability. I think I said in my remarks that we'll see exactly what happens. Obviously, it's impossible to predict in a very competitive rig market exactly how all of the competitors will respond, but we think there's reason for people to behave in a very disciplined form given a significant amount of demand for rigs at this time and a slowing of rig new builds.

Yes. That's fair enough. And my last one would be just along the lines -- you said you had 90 idle rigs. Do you guys -- what's your estimate of the number of total idle rigs that are available in the market right now?

I think, Kurt, we have no particular special expertise on that. The number that's kicked around is 300. We wouldn't see any reason to change that. I think there's another large competitor of ours who has a similar number to the number that we just described for ourselves, and I think the rest is spread about the industry.

All right. Hey, Mark, thanks.

Thanks, Kurt.

And our next question comes from the line of Geoff Kieburtz with Citigroup. Please proceed.

Thanks. Good morning.

Good morning, Geoff.

Could you quantify for us the magnitude of the term contract buyout?

It's about a hundred dollars a day, a little less than that.

Okay. So that was the effect on margin and revenue?

Yes.

Okay. And in kind of to continue on a little bit on this, the term subject, what was the average number of rigs that you had on term contract in the fourth quarter?

I don't have that.

Geoff, I would just be guessing. We had approximately 12 rigs come off term contract during the fourth quarter, a similar number we just mentioned, we will come off again in Q1. So the average number of term contracts was probably in the mid 50s.

Okay.

You see, at the end of the year, we had 47. Twelve expired and are set to expire this quarter. We're thinking that the same number expired in the appreciating quarter. So we'll -- we don't have that number, but you can sort of back --

That's close enough. That's fine. Thank you.

Okay.

Are you signing any new term contracts, or should we assume that term contracts expire, but there's no new ones being signed for the time being?

Geoff, I think, for the most part, we are signing some, what I would call some shorter-term type contracts, but they typically are less than 12 months. In the past, we've always considered a long-term contract something in excess of a year.

Right.

We've had a number of three-month, six-month, nine-month extensions. But quite frankly, we have not seen a whole lot of interest today in people signing up two and three-year new contracts unless it's on new equipment.

Right. Okay. And what do you have coming into the -- at this point for first quarter or first half, in terms of new equipment that is on term, but not in the fleet yet?

Specifically that's on-term?

Yes.

The answer would be nothing.

Okay. That's good.

I mentioned we've got the two new rigs coming out. They're coming out virtually this week. But we did not sign term contracts with those two rigs.

All right. And I'm going to make a stab at this. I don't know if you have the number. It's -- do you have an estimate of what your per-rig-day margin would be in the fourth quarter if everything were on today's spot rate, if everything were marked to market, you had no term whatsoever?

Geoff, I don't have that calculation, but my take is that it would not be significantly lower than where we are today.

Interesting.

I would -- my take is it would be within $1,000.

Okay.

But that's a stab in the dark on my part.

Yes, I think that's fair. We obviously haven't calculated that number. But as you know, we had certainly had less term contracts from some of our competitors.

Sure.

We've seen a number of them -- a number of the early ones have come off, but as I mentioned, it's a hard thing to calculate, Geoff, because like I said, we had some one-year terms and two-year terms and some three-year terms.

Right.

So it's -- I think John is probably pretty accurate in the answer he gave you.

Okay. Great. And my last question is just simply on the fluid. You made a -- I think a non-committal comment about not seeing anything in '08 that's going to materially change the fluids business. I'm assuming that is a -- reflects a view on the Gulf of Mexico drilling activity. Is there anything in particular that we should watch? Is it the jack-up contracted -- jack-up count that would -- if that goes up, that we should expect something different from fluids than basically more of the same?

No. Geoff, I would say, as you know, the rig count in the Gulf of Mexico has declined year-over-year, I think, from 77 to about 55 or 56 today.

Yep.

Our fluids business has been heavily reliant on four or five very specific customers in the Gulf.

Okay.

And those specific customers just are not as active as they had been in the last couple of years.

Okay. So it's not a broad market comment, it's really on those specific operators?

That's correct.

Great. Thank you very much.

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

Good morning.

Hi, Arun.

I've got a couple questions on capital. You mentioned you spent about $1.5 billion in the drilling business over the last four years. I was wondering if you could give us a sense of how much of that was maintenance type of CapEx and how much of that was kind of new builds and upgrades and the like.

Yeah. I don't have a full breakout of the number here, but the maintenance capital has, over the last several years, run us in the area of $1,000 per drilling day. And I think that the maintenance capital component would be consistent over that period, and that tubulars would be in addition to that.

Okay. John, if you could estimate, you talked about 70 new and new-like rigs. How much did you spend on a per-rig basis for those 70 rigs?

It would be less than $10 million. If I had to venture a guess -- and this is a guess -- it would be somewhere in the $8 million per rig range.

Okay. That's helpful. In '08, you've talked about $480 million in CapEx for the drilling business. How many NOV new builds and --

Arun, that's $480 million in total.

In total. Pardon me. Pardon me. How much for the drilling business, and how many --

Let me give you some numbers for that, Arun, that might be helpful. Of the $480 million, we are saying, internally, that we think approximately $70 million goes into pressure pumping, approximately $30 million into other businesses. So $480 million becomes $380 million. The $380 million that's then going into drilling gets allocated in the following way -- approximately $130 million in maintenance, approximately $50 million to take those customized NOV IDEAL rigs and put them in the field, along with some other, in effect, refurbs of rigs that makes them like-new rigs, $190 million for upgrading our mud systems, top drives, pipe handling equipment and other systems which make our rigs more fit for purpose across the board, and $10 million miscellaneous, bringing you to a total of $380 million.

Okay. That's great detail. Thanks. Doug, you've added, I think, 11 walking rigs and a handful of ideal rigs. Is that helping the mix and the margins on those rigs substantially different than the [81 35] you did this quarter?

Arun, I would say the answer to that question is yes. Obviously those rigs are going into the marketplace at higher day work rates, because they're, in essence, new equipment. We certainly have some short-term advantage in terms of repair and maintenance cost. But I think you also have to recognize they're much more sophisticated equipment, too, things with electronic drilling systems, hydraulic pipe handling equipment, iron roughneck, FCR. We also have -- overall, have higher ongoing upkeep costs. But generally, I think the margins on those rigs we've been very pleased with, and they have been helping the mix.

Can you quantify kind of where those margins are?

We'd rather not do that, Arun.

Okay. Okay. Last question, guys. Obviously, you've been spending some money in pressure pumping. Could you give us a sense of what you believe the replacement cost of your pressure pumping business is in Appalachia using currently market prices for --

Arun, I don't think we think about the business the way you just described it. I mean, we have a business there that is more than just the sum of its equipment and its facilities. I mean, we have been a market leader in Appalachia for many years. The business has enormous know-how. It has enormous goodwill, and we would never think about the business in terms of its equipment replacement costs. And for that matter, by the way, we don't think that's an appropriate measure for measuring our drilling business or our fluids business. There's expertise in these businesses and goodwill, and you can't just -- the old industry standard of saying, "What's it worth to -- in effect, on a pure equipment basis?" We don't think it makes as much sense to the business with as much knowledge and sophistication as currently is there.

Okay. Fair enough. Thanks a lot.

And the next question comes from the line of Marshall Adkins with Raymond James. Please proceed.

Hello, Mark. I'm a little perplexed here. When I go talk to investors, a lot of people perceive your fleet as a lower-end fleet, but somehow you're keeping margins and rates as high or higher than a lot of your competitors. How does that happen?

You know, Marshall, I think that the story that our rig fleet is inferior is one which our competitors would like the world to believe. I don't think it's a fair description of what we have. As you know, the walking rigs that we have put into the market are among the most sophisticated equipment there is in the marketplace. And in essence, I think you've just kind of confirmed the answer to your question -- the answer I just gave immediately beforehand, which is that there's a lot of expertise in our drilling business, and that expertise we think our customers appreciate. I'm amused at listening to a story one day in which one of our customers said that they were able to successfully do their ENP program because of some very sophisticated technology that was brought to Bear. The question that was said to him, "What technology is that?" Well Patterson-UTI was the answer. And that's the technology. And so I think that it's very easy to underrate and understate your competitor's abilities, which is what I think some people have done. I don't think it's true or correct.

Well, it certainly appears to be showing up in the numbers. Pressure pumping, pricing there is also done a lot better than elsewhere. Is that because of the geographic niche you guys have, or is it the new equipment you've added? Or help me understand why your business there seems to be doing so much better than others.

Marshall, I think there are a variety of reasons for that. One we're a very solidly entrenched oil service up in the northeast. Our people have been there. We have an outstanding reputation in the marketplace. The business, as you know, up there, has taken off. There's a lot of people very excited about the Marcellus Shale play. And it's a very broad aerial extent. But I think we're known for our outstanding capabilities there. We have kind of fed the tiger quite a bit in the last couple of years to try to increase our capacity. And very selectively, we've made sure that we've pushed our pricing as well.

Okay. Last question, Mark. You've done a better job than many in the oil service arena of getting cash back to the shareholders in a couple of different forms. What are your plans there going forward, or are you still looking at ongoing share buybacks, or are you going to start reinvesting one biz? Obviously, you have a pretty good CapEx budget this year. Help me understand what your plans are there.

Sure. Thanks for the compliment first. We are quite proud of this combination that we've been able to achieve of significant reinvestment. The $1.8 billion reinvested in the business, plus the $700 million that we've given back to the shareholders, and a balance sheet that's still debt-free as of today. So that -- we are really -- that is something we're really quite proud of. We just announced obviously that the first quarter dividend is being paid out, again, at the end of March, just as we have been doing for a number of years. In terms of the buyback plan, we have, as you probably know, based on the numbers released this morning, $180 million left on our buyback authorization. We probably will not be spending a lot of money immediately, given current market conditions and a desire to make a significant investment as is set forth in the CapEx plan that we've been discussing already during this call and in our press release, and our expectations for free cash flow generation from the business. On the other hand, to extent to which there is excess free cash flow over and above what we invest in the business, and we have historically used it to buy back shares. And I can't see any reason that we wouldn't follow that suit to the extent to which there's excess cash flow over and above what we're going to reinvest in the business in CapEx.

But you probably wouldn't lever up at all to buy back stocks. Is that fair?

We don't have plans to do so. We wouldn't rule it out as a never.

Okay. Great. Thanks.

And the next question comes from the line of Ian MacPherson with Simmons & Company. Please proceed.

Hey, good morning.

Good morning.

Mark, I'm just curious about the remaining IDEAL rigs that you're building out. I think you ordered that equipment from NOV about 18 months ago, and I'm just curious what the strategy has been behind -- it seems like you're taking your time in getting those rigs into your fleet. And it would strike me as beneficial to your mix if those were working as opposed to being gradually phased in. So if you could maybe --

Ian, I'm going to let Doug answer that.

Okay.

Ian, you are correct. We did order that equipment about 18 months ago. Most of it was delivered throughout 2007. As you know, we ordered 15 of them at one time. We decided last year, in midsummer, to put one of them together and introduce it to the marketplace. We had a very thoughtful process as to how we planned on introducing these to the market. As you know, at the time, there was a lot of rigs excess capacity in the market at the time. We decided not to, as a kind of one fell swoop, add a whole lot of additional capacity. We wanted to specifically look for incremental demand. We've kind of stuck to our guns on that. I mentioned earlier we're planning on building two at a time, one in Victoria, one in Tyler. And we're pleased to say that the two that we started in late November are moving to the field this week and should be spotting next week. We will start two more of them right away. Our plan is to continue to do that as long as we see incremental demand. And you're correct, we do see that the margins and the rates on those rigs are higher, but we have very clearly tried to come up with a game plan not to flood the market with these rigs.

Okay. So I don't think I quite caught -- what do you think the cadence is for two by two each quarter or each month? I didn't capture that part.

They take 60 to 75 days to put together. You know, we might speed that up. We might slow it down, depending on the demand. But we have at least planned to have most of those rigs in the marketplace by the end of 2008.

Okay. If I could just add some quick follow-up on the 90 rigs that you have available on the sidelines. If demand does creep up to require some of those rigs, would you have a significant refurb cost associated with those, or are they still warm enough that they could go into the market pretty seamlessly?

I think pretty seamlessly, Ian. Most of those rigs have worked at some point in time within the last 12 months. We have analyzed rig by rig. But as you know, that 90 rig number, it's not the same 90 rigs depending on the area that we're working in. Most of the rigs that we have today could go back to work very seamlessly. I would say there's some in the fleet that would require a minor amount of capital before we put them back to work. But for the most part, they could go pretty seamlessly.

All right. Thank you.

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

Good morning, guys.

Good morning.

Doug, we've seen a couple of transactions recently with a service company buying a land driller or a land driller buying a service company. Given the experience you have on both sides of the fence here, I wanted your thoughts on this. Do you think this is a trend we'll see more of? Is it a positive thing, or are there going to be cultural issues in the integrations here?

Mike, I think, looking at both of those deals, they're very specific deals. I think you have to look at them as transactions that the people knew each other on both sides. Obviously, the one deal with [Al Charmers], we're encouraged by that a little bit. They've at least publicly announced that they may move some of those rigs internationally. We think that's good for the U.S. market. The second deal, I think, was really -- I think there are certainly some related parties on both sides of that deal. I don't see it as being a trend in the industry. I think, for a long time, the land drilling industry in general has been looked at as a separate entity and does not have a whole lot of, I guess what I would call, synergies with some of the other oil field service businesses. Certainly in terms of bundling packages, I don't think it's a requirement. So I don't see it as being a trend that will continue. There may be some -- certainly some international opportunities for people to do that, but I certainly don't see it as being a huge big trend.

Okay. And then, one of the other things people are looking at is moving rigs internationally, as you've discussed here. Is this something you guys have looked at and would be interested in?

Well, we've looked at it. Quite frankly, most of the deals that we've seen so far are not terribly interesting to us. People assume that the international business by itself is just so much better. It's not necessarily the case. As I've said, we're actively looking, but we have no plans in the immediate future to move rigs internationally. If the right deal comes along, we would certainly look at it. But I think, for the most part, there's a very limited number of opportunities. I think, as you know, the land rig market internationally is something like 850 rigs, which is smaller than the number of rigs that are just in Canada. So I think the opportunities are few and far between, and you certainly have to pick your spots.

Okay then. Mark or John, I'm not sure which one of you would want to take this. You commented about how the fourth quarter numbers were positively impacted by Canada. Would this mean that perhaps in the second quarter, once we see the spring break out, the impact on revenues and therefore also margins will be greater than what we've seen in previous years?

Yes. I think we might have misstated or you might have misinterpreted that the comments about Canada had to do with the higher revenue per day related to some incremental equipment that gets used in the first quarter. There was a similar offset in costs. So from a margin perspective, it was fairly neutral.

Okay.

But as you look to the second quarter, certainly the Canadian margin is lower. The industry there comes close to a shutdown in the second quarter while they work on equipment and get it ready for the coming 12 months. So my expectation, I guess, or my guess is that we would see a sequential decline in drilling margins somewhere toward maybe $300 or $350 in the second quarter -- that's a guess -- which is an incremental impact of the Canadian rigs not working yet in most of the cost [standpoint].

Okay, guys. That's it for me. Thanks a lot.

And our next question comes from the line of Waqar Syed with Tristone Capital. Please proceed.

Hi. Could you provide some guidance on DD&A and G&A expectations for next year?

Yes. As we continue our capital program depreciation will continue to ramp up some. And if I look at kind of the first, second quarter, I think the first quarter would be somewhere around $66 million and then probably increasing $3 million, $2.5 million, somewhere between $2.5, $3 million per quarter, depending on the timing of the CapEx and when things come into the marketplace.

Sure.

G&A-wise, I don't see it ramping up significantly, but possibly somewhere around a $0.5 million per quarter.

O kay. Now, do you expect any drop in the first quarter from the fourth quarter, if there's some seasonality to G&A in the fourth quarter, or no?

Yes. You can have a little bit of that. Fourth quarter, you get a little bit of the bump in the things in some of the markets and some of the things that go on, but I wouldn't expect a significant adjustment for the first quarter.

Okay. Good. One other thing. One of your competitors has been recently saying that they've introduced new rigs, and not just the traditional and unconventional plays, but also in the conventional plays. And they think even in the vertical well market, they've had some efficiency gains, and that I think in the west Texas area, third party reports are that they've recently drilled some of the fastest wells ever drilled in that market, and they've just been operating there for about six months. Do you see any competition there from new rigs, even in the traditional vertical well market as well?

Well, I think, you know, the new rigs are going into all sorts of markets. I don't think it's just the unconventional plays. In fact, if you think so far, two out of the three new rigs -- the new NOV rigs that we've introduced to the marketplace are working in south Texas, which you would consider to be a pretty traditional vertical market. So I think you have to look at region by region. I don't think the new rigs are just specifically going into the unconventional plays. There's a combination of new equipment going into all sorts of markets.

But even in like the shale where vertical market in the west Texas area, which is something that you guys have dominated in, have historically had very good efficiency in that market.

We have not seen a lot of new rigs enter that market. Obviously, there's one very specific case that I think you're referring to. And we're still in that market competing against those new rigs. Interesting enough, based on the data that we've seen from all of 2007, our cost per foot data is still 25% below that of those new rigs that are in that market. So all of those stories about new fit-for-purpose equipment taking over and providing more efficiencies, generally I would say it is true, but there's some very specific markets that the facts just don't bear that out.

Sure. Thank you very much.

And the next question comes from the line of Pierre Conner with Capital One South Coast. Please proceed.

Good morning, gentlemen.

Hey, Pierre.

The first question is about, actually, on Universal Well Services. Can you give us a feel for where you ended up on horsepower? And then, you indicated continuing to add some more horsepower, what that horsepower number would be or what are you adding?

Yes, Pierre. We've been adding a lot of horsepower throughout the various segments of that business, and you almost have got to break it down by frac-ing and nitrogen and cementing. I'll talk specifically about frac-ing, because it's probably the area that everybody's the most interested in. We exited 2007 at just under 72,000 hydraulic horsepower. We think we'll exit '08 at something in excess of 110,000. So, we've added a significant component of horsepower. To give you some idea of the average frac job in the northeast sort of prior to all the current interest in the Marcellus was, you could have 1,000 to 2,000 horsepower to do one of the typical fracs in the Appalachians. Some of these deep horizontal fracs are going to require somewhere between 15 and 25,000 horsepower on a location. So you just have to have enough equipment to make sure that you can do that. And we plan on having enough equipment so that we can do at least two of those horizontal fracs at any one time, plus handle all of our traditional business. So I said that's on the frac-ing side. That's primarily what we've added. We have added a lot of nitrogen stimulation capability as well, probably about a 30% increase in our horsepower there. The cementing business, we haven't really seen any huge big changes. And quite honestly, we've added some horsepower capability for cementing, but it's nowhere near the nitrogen and the frac-ing.

Thanks. Okay. That's helpful. The next question is with the currently available fleets. What would be the indications you'd be looking for to begin to bring some of those rigs that people have asked a little bit about? What would it take? So would it be incremental backlog on the existing actual day rates improving? Just what's the context by which you would potentially bring those additional rigs out?

I think it's really a case-by-case decision in each market and with each rig, made typically by the regional person in consultation with the operations people and marketing people here in Houston and under ultimately Doug's decision-making. But it's really case by case where you look at demand in the marketplace, rigs available in the marketplace, pricing in the marketplace and all those factors and try to make a decision as per each rig.

But given --

It is not -- I want to try to emphasize to you, it's not a top-down but rather a bottom-up decision.

Okay. Okay. So it's where they would see the ability to put the rig to work without damaging currently pricing or activity.

And also, you're obviously not interested in mobilizing a rig going through all the startup costs for a one-well --

Return.

Commitment. You're looking for a multiple-well opportunity. And you're looking for a situation in which the pricing makes sense for that additional incremental rig.

Right. It seems like the pretty big asset there, opportunity based, and you mentioned the incremental demand still for fit-for-purpose equipment. And this has obviously been brought up to spec currently, but is there an opportunity for real step function in its operability? Take for example, can you take equipment that you have and convert it to skiddable rigs? Has it been looked at and what is the magnitude of that kind of a thing?

Yes, certainly. We're looking at the fleet today, and there's no question that you can take current equipment and modify things to get a very, very efficient rig today. One of the things that we talk about, all of the bells and whistles that we put on the new technology rigs. But in a lot of cases, the single biggest impact has been higher horsepower triplex pumps. And you can make a significant improvement in the efficiency of a rig just by putting bigger pumps on the rig. We do look at some other things. Obviously, you can reconfigure the backyards of rigs to get them to move quicker. When you get into EDS systems and top drives, it's a little more difficult just adding those things to older-type rigs. Some of the older mass and derricks just aren't capable of handling top drives.

Enough derrick-types.

But we've looked at all of those things, and we have a very active program at improving the efficiencies of those rigs that we think just makes a lot of sense.

So if you would potentially look at this fleet --

Let me interrupt you. Not only are we looking at it. Our capital expenditure plans for 2008 include significant capital to do just that.

Okay.

And part of the almost $200 million that I described as part of the $380 million for CapEx for our drilling comp segment is going into that exact issue of upgrading our pumps, our mud systems and the things that Doug was just describing, which have the effect of, in effect, taking a rig and making it virtually new in its application.

Okay. That's what I was looking for. So these compete with your fit-for-purpose --

Yes, and let me say this to you. We've been doing this for a number of years.

Yeah.

One of the things that I try to emphasize in the CapEx weave we've spent is we've been doing this. And this is that is one of the reasons why -- to go back to a prior question and a prior answer -- we think that our fleet is of significantly different caliber than some of our competitors would like to acknowledge because of the capital investment program we've had for a number of years where we have, in fact, upgraded a large number of our rigs.

All right. Okay.

That is the long answer.

Got it. Thanks, Mark and Doug.

Thank you.

I'll turn it back.

And the next question comes from the line of Scott Gruber with Bernstein. Please proceed.

Yes, good morning.

Good morning, Scott.

What's your contract rollout schedule in Q2 through Q4?

I don't think we have that information with us here.

Is it going to be about the same magnitude, 10, 12 rigs rolling off per quarter?

It's actually a little bit smaller than that. I think we'd think the first quarter was the most -- was going to be the most dramatic and it would slow thereafter.

Okay. So your indication that the margin impact beyond the first quarter was mainly due to fewer rigs rolling off contract?

John, do you want to respond to that?

And not a difference in the spread to working rates?

I guess I'd like to circle back to an earlier question. I played around a little bit of the math as Geoff Kieburtz asked his question. And I think the impact of difference between term con -- if everything on term went to spot, how much would that impact margin right now? I think that impact is less than $500 per day. Earlier we said it was a thousand or less, but I think it's under $500.

So the rigs that are rolling off in the first quarter, are they working at higher rates than the ones that are going to be rolling off the rest of the year?

I don't think you can say that. I couldn't answer that with any degree of certainty. Those rates -- it depends on when the contract was signed. We had contracts that were signed three years ago that have lower rates than contracts from, say, a year ago. So it really is all over the map.

Okay. That's it.

Thank you.

And the next question comes from the line of Todd Garman with Peters & Company. Please proceed.

Good morning. In Canada, Doug, do you have any visibility as to activity levels in the back half of the year, and has that changed recently one way or the other?

Yes. I really don't have that visibility, and I couldn't quote you the numbers on the PSAC survey that everybody uses up there for activity. But I think directionally, what we heard is that it was a pretty dismal survey. They expected very low levels of activity. And we don't see anything on the horizon that gives us any great degree of comfort that the back half of the year in Canada is going to be very good at all.

Do you see any signs now of clients taking rigs on windows where they can?

In Canada?

Yes.

Well I think now -- typically in the wintertime, there's a lot of locations that we drill that are only accessible in the winter. So I think that kind of drilling today is sort of just ongoing and it happened. I think the real question will be is, what does the rig count look like coming out of breakup? And I don't think it will be so much of a question of customers looking for windows. I just think the amount of work up there after a breakup is going to be few and far between.

Okay. In the U.S., in the pressure-pumping business, is there anything on the product supply side that might prevent you from increasing or utilizing the equipment in which you intend to build here for the year, like whether it's gases or sand or --

Well, the only -- I would say generally no. Sand is obviously an issue in the northeast. But we've found that we've got three or four different suppliers. And because of our long-standing relationship with those suppliers up there, I think we've had access to some products and things that are going to be difficult for other people to get. But we think we've got our supply locked in.

Do you have an [okay or pre]-agreement percent in that area?

Not that I'm aware of.

Okay. Thank you.

And our next question comes from the line of Kevin Pollard with JP Morgan. Please proceed.

Thanks. Good morning.

Hey, Kevin.

I just wanted to close the loop on these questions around your capital budget and the upgrading of the fleet, some of the stuff that Pierre was just touching on. If I look at the substantial budget you've got for upgrading and the $50 million for the IDEAL rigs, how would your fleet of new or like-new rigs stand at yearend '08 versus the 70 that you have now?

You're saying what would the number be?

Right.

Well, it will be closer to 90.

And that includes all 14 additional IDEAL rigs?

If we put out the remainder of the IDEAL rigs plus the continued refurbs and some additional walking rigs that we're contemplating in '08, that number would get pretty close to 90.

Okay. All right. Thanks. And if I could just switch gears over to Appalachia, you've talked a lot about your expansion programs for the pressure-pumping business. I know you've moved a few rigs into that market. I was just wondering, given the growth of that market experience, if you could talk about your plans on the rig side.

I think it's a pretty competitive opportunity, and I think we'd just like to tell you that we think it's a really interesting opportunity.

Okay. Thanks a lot.

Gentlemen, currently no other questions.

Before we say good-bye, I think there's one more comment that John Vollmer would like to make about a pretty technical area of our business.

It's not really that technical but -- one question that didn't come up, and I think people trying to do projections would want to be aware of is tax rate-wise, we expect our tax rate to be a little bit higher in 2008 than it was 2007. And our current estimate is it would be about 35.5%. I thought you might want to consider that as you're working through your estimates. That's all I had.

Thanks, John. Again, we thank all of our employees. We thank all of our investors, and we look forward to speaking with you at the end of the next quarter. Thanks, everybody.

Ladies and gentlemen, this does conclude the presentation. You may now disconnect. Thank you very much. Have a great day.