Patterson-UTI Energy Inc (PTEN) 2010 Q3 法說會逐字稿

Good day ladies and gentlemen and welcome to the third quarter 2010 Patterson-UTI Energy earnings conference call. My name is Katie and I'll be your coordinator for today. At this time, all participants are in a listen-only mode. We will be conducting a question and answer session towards the end of the conference. (Operator Instructions)

I would like to now hand the call over to Mr. Geoff Lloyd. Lloyd, over to you please.

Thank you very much, Katie. Good morning. On behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the three and nine months ended September 30, 2010. Participating in today's call will be Mark Siegel, Chairman, Doug Wall, President and Chief Executive Officer, and John Vollmer, Chief Financial Officer.

Again, just a quick reminder that statements made in this conference call which state the Company's or managements 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, deterioration in the global economic environment, 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 drilling 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 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, which may be obtained by contacting the Company or the SEC. These filings are also available through the Company's website or through the SEC's EDGAR system. The Company undertakes no obligation to publicly update or revise any forward-looking statements. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on the Company's website, www.patenergy.com, and in the Company's press release issued prior to this conference call. And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Geoff. Good morning. Welcome to Patterson-UTI's conference call for the third quarter 2010. Thank you all for joining us this morning.

Third quarter 2010 was excellent for a number of reasons. Most importantly, we witnessed further improvement in our core businesses, both of which performed ahead of our expectations. We have now seen our US rig count increase for 16 straight months, despite continued investor concerns throughout the year about low natural gas prices. For October we estimate that our rig count in the US will increase by an additional five rigs sequentially. Although many investors are now again worried that low natural gas prices will cause activity to decline, we have seen steady rig count growth throughout 2010, including in October.

Our Appalachian pressure pumping business also had an excellent quarter with record-setting revenue and earnings. Continued strong activity levels in the northeast and pricing improvements for horizontal fracs have led the way. The quarter was also noteworthy in other ways as well. We completed the previously announced transaction to purchase the pressure pumping and wire line assets from Key Energy. The transaction closed immediately following the end of the third quarter on October 1. For that reason, our reported results today do not reflect any contribution from these businesses. We are pleased to welcome the new employees to the Patterson-UTI family. We look forward to their contributions in the quarters and years ahead. As I have said, the strategic transformation of Patterson-UTI is moving forward and we are pleased with the strategy and its execution.

Our press release for the quarter was issued earlier this morning, and I trust that by now all of you have had an opportunity to read it. We will comment on the highlights from the quarter. Before we get into the details this morning, our plan would be to take a few minutes to review the financial results for the three-month period ending September 30, 2010. I will then turn the call over to Doug Wall, Patterson-UTI's President and CEO, who will make some detailed comments on the results of the individual operating units, as well as sharing some operational highlights. After Doug's comments on the third quarter, I will share a few brief thoughts on the market outlook. As always, we will be pleased to take your questions following these prepared remarks.

We are pleased to report this morning that the Company recorded net income of $29.4 million, or $0.19 per share for the three month period ended September 30, 2010. This compares to a net loss of $18.6 million, or $0.12 per share for the three months ended September 30, 2009. Revenues for the quarter were $379 million, compared to $160 million in the same quarter last year, an increase of $219 million. On a sequential basis, revenues in the third quarter improved by $72 million, or more than 23% as compared to the second quarter. We were very pleased with the sequential revenue growth with our drilling business recording an improvement of 21% and pressure pumping recording revenue growth of 37%. EBITDA for the quarter improved to $138 million. On a sequential quarterly basis, EBITDA, excluding the proceeds from our E&P rights sale last quarter, improved by approximately 32%. This substantial sequential improvement in EBITDA was the result of better operating performance in both segments of our business.

Capital expenditures for the third quarter were $215 million, bringing our nine month total to approximately $514 million. Most of this CapEx relates to our Apex rig new build program, which Doug will speak about later, as well as new frac equipment, some of which we have advanced from our 2011 capital plans. During the quarter and in preparation for the Key acquisition, we put into place a new bank facility which provides a $100 million term loan and a $400 million revolver. At the end of the quarter, we had $26 million in net debt composed of $74 million in cash and $100 million in term debt. After the third quarter, we completed the private placement of ten year senior unsecured notes totaling $300 million at a very favorable rate of 4.97%. We believe that the combination of our healthy balance sheet, the attractive financing, and projected cash flow from operations provides us with the necessary capital to continue our strategic growth in our two core businesses, land drilling and pressure pumping. I would now like to turn the call over to Doug, who will further discuss our operations for the quarter.

Thank you, Mark. I want to start this morning with some commentary on the drilling company and then follow up with some commentary on pressure pumping. For the quarter ended September 30, 2010, the Company had an average of 178 drilling rigs operating, including 170 rigs in the US, and eight rigs in Canada. This is a 22-rig increase, or approximately 14%, over the average activity level we experienced in the second quarter. The US improvement of 16 rigs from the second quarter was further proof of our ability to meet the demands of the industry with efficient rigs. The biggest activity increases came from Appalachia, where we were up five rigs, and then three rigs each in south Texas, the Rockies, and the mid-continent. This broad across the board strength in rig activations confirms our long standing conviction that it takes a wide variety of rigs to satisfy the diverse needs of the overall market place.

Rig pricing also continued to improve during the quarter. Once again, driven by the steady increased demand for quality rigs. As virtually all of the high-technology 1,000 and 1,500 horsepower rigs are now working, pricing has improved on the next tier of very capable rigs. The increasing demand for rigs destined for the oily basins has also helped to improve overall pricing. This pricing momentum comes largely from spot market rigs, which currently account for roughly 65% of our active rig fleet. We still do have additional capacity capable of going back to work in many of the regions, particularly west Texas, mid-con, and the Rockies. Overall, we feel we are very well positioned to benefit from any demand in the liquids-rich and oily basins of the US.

Apart from a trickle of new builds entering the market, it's pretty apparent that almost all of the high-end rigs in the industry are now working, with most under some type of long-term commitment. Because of this, we continue to see increased customer interest in our high quality mechanical rigs and expect to see additional demand in this area in the coming months. In fact, during the quarter, we signed term contracts for three of these mechanical rigs. As we have said before, we believe that our diverse rig fleet provides unique opportunities to provide incremental rigs for our customers and ultimately very good returns for our shareholders.

Average revenues per operating day during the third quarter were $17,730, compared to $16,920 in the second quarter, an improvement of $810 per day. Average direct cost per operating day increased slightly to $10,670, compared to $10,520 last quarter. Daily drilling margins increased slightly better than we had expected, improving by $670 per day during the quarter.

Canada is now gearing up for the Winter drilling season. We currently have 12 rigs currently working and a number of operators are waiting for freeze up so they can begin operations. Despite the upcoming holiday season, we expect the fourth quarter rig count to average 195 rigs, which includes on average, 10 in Canada. We expect average revenue per day to increase by $1,000 and average daily drilling margins to increase by approximately $700. Increases in wages in certain markets are driving some of this cost increase.

In respect of term contracts, we were able to secure 20 new-term contracts during the quarter. Now let me break this down for you. We signed two additional new builds. We signed eight existing Apex rigs to new-term contracts. We signed seven other FCR rigs to term contracts. As I mentioned before, we signed three mechanical rigs to term contracts. During the third quarter, we had an average of 54 rigs working under term contracts. Based on contracts we currently have in place, we expect to have an average of 68 rigs working under term contracts over the fourth quarter, and a total of 65 for 2011.

Let me give you a quick update on our 2010 new build program. In total, we delivered five new rigs to the market place in Q3 and three more were delivered in the first three weeks of October. Of the five rigs delivered during the quarter, two were Apex 1500s. One is working in the Eagle Ford, the other in Haynesville. One additional Apex 1000 was delivered to the Marcellus. And two new APEX walking rigs were also delivered to the Marcellus. We now expect to complete 21 new rigs this year with another two rigs, which were originally scheduled for 2010, now being delivered in early January of 2011. We are pleased to say that we have term contracts signed on all of them. We are still seeing a lot of ongoing interest in our Apex rig technology, and are in current discussions with numerous customers regarding further new builds and term contracts for 2011. For our 2011 Apex new build program, we are planning to add 21 additional Apex rigs to our fleet. This concludes my remarks on drilling.

Let me turn now and talk about the pressure pumping business. Please keep in mind that the results I'll comment on relate to our Appalachia business only. As Mark mentioned earlier, no revenue or earnings were recognized by us during the quarter form the Key assets. We are extremely pleased with the performance from our Appalachia pressure pumping business this quarter. Our revenues were up 37% sequentially and our operating income more than doubled to $17.6 million. Revenues for the quarter were $81.1 million, a new all time record for universal and beating our previous record high by approximately 34%. Average revenue per job came in at just over $40,000, which was up almost $8,000 per job sequentially and over $5,000 per job higher than our previous best. The number of jobs completed during the quarter increased sequentially by 9%, with frac jobs leading the way with a 16% increase. With the onset of the Summer weather up in the northeast, we did not experience any of the customer delays that we saw in Q2.

During the quarter, we completed 35 Marcellus horizontal fracs with our two dedicated frac crews in this region. This was an increase of 10 over the previous quarter. We also pumped 22 horizontal nitrogen stimulation jobs in Kentucky and Tennessee. Cementing revenues were up over 30% sequentially. Overall drilling activity in completions in the Marcellus Shale continues to increase as a number of new customers get underway on their projects. We continue to be very excited about this market and expect this to translate into further improved demand for our services as we head into 2011.

Now looking at Q4, due to the onset of Winter weather, some shorter days, and some lost days we typically experience which can be attributed to the holiday season, we do expect a slight pullback in Q4 revenue to approximately $70 million to $75 million. However, year over year, we expect this market to continue its strong growth. For the fourth quarter, we expect our EBITDA margins for the Appalachian business to be around 38%.

During the quarter, we continued to take advanced delivery on some of the new equipment required for our next quintuplex frac spread. We now have a total of 29 new quints in service in Appalachia. We expect an additional seven quints to be delivered prior to the end of the year, with nine more to come in Q1 of 2011. This equipment will be put into service to round out our third dedicated horizontal frac crew in this market.

Obviously, we continue to be very encouraged by the ramp up in industry activity in the Appalachians, and we feel we are extremely well positioned to service this market. We have opened up our new facility in Williamsport, which will house our northern Marcellus frac crew. We expect to see further efficiencies in our operations by placing our crews and equipment closer to this very hot, growing market. Appalachia has become a very significant business for us in both pressure pumping and for the drilling company. We're very pleased with our positioning in both businesses, and we expect to see continued growth in this market for years to come.

Before turning the call back to Mark, let me make a comment or two on our recent acquisition. We're very excited about the acquisition of Key's pressure pumping and wireline assets. The first four weeks of this transition has gone remarkably smoothly, and we're very pleased with what we have seen to date. There continues to be high demand for our equipment and services. We're currently talking to a variety of customers regarding their ongoing needs for 2011 and beyond. In terms of the operations, we plan to operate these businesses under the names Universal Pressure Pumping and Universal Wireline. Our Universal Well Services group in Appalachia will continue to be run separately by local management.

Although we're not able to provide much historical information on these newly acquired assets, we do want to provide you with our expectations for the fourth quarter relating to the assets we have purchased. We expect these assets to generate revenues of between $70 million and $75 million, a revenue expectation that's in line with our similarly sized Appalachian business. Although we have very limited information, we expect our EBITDA margins for these new businesses to be in the neighborhood of 29% for the fourth quarter. We are hoping to see margins improve over time in these businesses.

One last comment before I turn the call back to Mark. With respect to CapEx for the Company in 2010, we now expect our total CapEx spend to be approximately $700 million, which includes early delivery of certain rig components and frac equipment that was originally ordered as part of our 2011 capital projects. We will be finalizing our 2011 capital budgets and we will provide further details on our next conference call. With that, I'll now turn the call back to Mark for some concluding remarks.

Thanks, Doug. We're very pleased with the operating and financial results for the quarter, as well as the overall progress we have made as a company this year. We have a plan, and we are making progress on it.

Our industry has changed dramatically over the last several years, and Patterson-UTI has responded to these changes. The biggest -- the single biggest impact in the North American land business has been the development of horizontal drilling and completion techniques. Although these changes started many years ago, the impact over the last three years has been incredibly dramatic. For the third quarter, approximately 65% of our revenue in the drilling business was generated from the drilling of horizontal wells. Over 50% of our pressure pumping revenue comes from horizontal fracs and stimulation work. The combination of new technologies required to drill and to complete these wells caused us to rethink our strategic positioning in the market place several years ago, and to reinvest in new equipment to target these fast-growing markets. We feel we are now very well positioned in two of the biggest and most important segments of the horizontal business, drilling and pressure pumping. By the end of the year, we expect we will have built approximately 70 high-technology drilling rigs over the last four years, focused, almost exclusively, on technology for horizontal drilling and shale plays. We will continue to add new equipment for these applications and markets as customer demand dictates.

Over an even shorter period of time, we will have added over 70,000 horsepower to our pressure pumping capabilities in the Appalachians with another 38,000 horsepower to come prior to the end of first quarter 2011. We will have also added over 214,000 horsepower in new markets, such as the Eagle Ford, Permian, and the Barnett, by way of our acquisition of Key's pressure pumping assets. To put this in perspective, we have increased our pressure pumping horsepower by more than six fold since December 31, 2006.

The drilling and stimulation markets have changed, and so have we. We have repositioned Patterson-UTI to respond to these changed markets and at the same time we have maintained and improved our capabilities to satisfy the needs of conventional markets.

A few comments on the market outlook for the balance of 2010 and beyond. In short, we remain cautiously optimistic. As we have said before, we have been pleasantly surprised by the resiliency in the rig count, driven by two factors. First, shale plays and other conventional resource plays. Second, oily and liquids rich plays.

As I said at the outset, concerns respecting a decline in activity levels from low natural gas prices have been a recurring theme in 2010. While we recognize the short-term risks, we want to reiterate our strong feelings for the long-term potential for natural gas in North America. Our conviction in the long-term prospects for the market is bolstered by a number of developments that we have seen in 2010. Including the almost $14 billion that non-US investors have invested in land-based natural gas shale plays, and the growing conviction on the part of some utilities that natural gas prices will determine, to a very large extent, the price of electrical energy in the US for the foreseeable future.

Finally, one additional comment respecting oil and oily plays. During the quarter, we were pleased to hear a report about the new hot basin, the Permian. Of course the Permian is not entirely new, and this is an area of historical strength for Patterson. We believe that continued development of certain oily plays will certainly benefit our Company.

As I said earlier, we think we are on the right track in both of our core businesses and this quarter's results support that conclusion. In closing this morning, I'm also pleased to announce that the Company declared a quarterly cash dividend on its common stock of $0.05 per share to be paid on December 30, 2010, to holders of record as of December 15, 2010. Looking back, we have accomplished a great deal over the last quarter, the last year, and the last several years. Once again, this industry has shown a cyclical nature, and I know how difficult this can be on our people. I would be remiss if I didn't thank our employees throughout the United States and Canada for their efforts each and every day in working safely and efficiently. I also want to welcome new employees from the Universal Pressure Pumping and Universal Wireline businesses. Thank you for your efforts during the transition process and we look forward to your contributions to the success of Patterson-UTI. Thank you. At this point, we will open the call for questions.

(Operator Instructions) Please hold while we compile a list of questions. Your first question comes from Marshall Adkins from Raymond James.

Good morning, gentlemen. Let's jump right in on the rig side. You got 192 rigs, looks like, are running right now. How many of those would you say are new generation rigs? By that, I mean rigs that are brand new or have been substantial refurbed in the last, say, four or five years?

Marshall, that number is probably in the 110 to 115 range today. We feel we have probably 70 to 80 rigs today that are not those kind of rigs. Just to break down the 115. Virtually, all of our new rigs, which would today be in the order of in the low 60s, as you know, there's a number more coming before the end of the year, we have 40 to 50 of what we would call good-quality SCR rigs that have been refurbed in the last four or five years also currently at work. So, the break down is probably 115 of what you're asking and there's another 70 or 80 rigs of what we would call our conventional fleet.

So, it sounds like to me that in terms of your fleet make up, your number of high end rigs is pretty close to any of the other guys out there at this stage, and you're also adding new ones at roughly the same pace as the other guys. So, in terms of rig fleet quality, pretty close parity between, say, you and neighbors in H&P, et cetera?

I think that's true. We certainly have come a long way in the last couple years in terms of catching up. As we also mentioned, we're continuing on with our new build program. We're pleased with the progress we have made.

All right. Just to kind of help me to understand a little bit better, it does sound like incrementally from here, so everyone is growing the same on the high-end fleet, but given the strength in the Permian, your other rigs, if we just call them that generally, are seeing a pretty nice pick up in demand certainly over the last quarter or two?

That's certainly correct. When I showed you the numbers of the rigs that we have signed term contracts, I must say that we were very, very pleased with the number of term contracts that we were able to sign during the quarter on what I would call this other segment of the fleet.

Is that a strategy change? I know in the past, you hadn't done a lot of long-term contracts.

Marshall, my reaction to that would be that frankly the customers have shown a greater and greater appetite for these contracts. Frankly, we have shown a greater appetite for them too as the years have passed.

[Any] pay out on those in terms of years, ballpark, not anything exact, just rough pay out?

It's hard to kind of generalize there. They range really from a year to 18 months. Obviously, the new builds are all three years. But the other group are anywhere between one year and three years.

I think Doug was answering the terms of those contracts. In terms of pay outs, Marshall, they are very hard to give you an easy across the board answer. Because, obviously, when we talked about the three mechanical rigs that were in our fleet, those are very different in terms of pay outs than would be the pay out, for example, for a brand new AC electric rig.

So, ranging from one to four years?

We don't have any four.

He's talking about pay outs. I'm kind of reluctant to say much more than one to four would be probably right. You're getting vastly different answers depending on what the nature of the contract is.

Last quick question for me. Help us with the margin trends going forward. Is there a big gap between your leading edge and your average rates? Are you going to reprice them higher? What should we look for over the next three or four quarters in terms of margin improvement?

We've been hesitant, Marshall, to speak to more than the next quarter. We've obviously seen a nice pick up in the third quarter. We have given you some expectations with regard to the current quarter of a $1,000 increase in revenue, which obviously speaks to average daily revenue per rig, which speaks to the fact that we are seeing positive trends in terms of our pricing. Going much beyond that seems pretty challenging under the circumstances. I think I can leave it there.

Okay. I'll let you off on that one. Thanks.

Your next call comes from the line of Arun Jayaram from Credit Suisse. Please proceed.

Good morning, gentlemen. I wanted to ask you a little bit about the guidance in pressure pumping. I just wanted to see if there's some conservatism to the guidance. I'd note that in Q2, you guided to 25% revenue growth in pumping and you did 37%. Just looking at your guidance for Key, not understanding about the seasonal factors, but it does suggest that Key's results versus what they reported and kind of their discontinued ops suggests essentially flattish type of revenues. I just want to understand how you are structuring your guidance.

Relative to the Key assets, frankly what was reported today by Key, we didn't have access to before you did, because of the asset acquisition. We had some financial information, but it was not complete. In our thinking about what we're going to say today, we simply looked at Key historically had a given revenue level of businesses similar size to our Appalachian business. We just in effect said it will do the same thing as ours at lower margins, because our understanding of their historical margins are that they have been less than our Appalachian business. As we have an opportunity to evaluate what Key put out today, our thinking could change. We may come to believe the revenue could be somewhat higher than what we said. However, we didn't have the benefit of that information prior to this morning.

Okay. Sounds like it's pretty conservative. My words not yours. The margins difference between you and Key was about 390 basis points on an EBIT basis. John, I know you've only had the assets for about a month or so, are the differences more on the cost side, on the pricing side? Any initial read on the margin differences?

I believe it to be pricing. We acquired it October 1, so we haven't even seen a month of operations. From what I know, I think we have been more successful at getting higher pricing with the business that we owned previously. We would endeavor to accomplish the best pricing we can for these assets going forward.

Okay. John, I missed a little bit about this. Can you reiterate how much capacity you're adding, how much of that is under contract, perhaps the timing of when it comes in and maybe some color about which markets it's going to?

Which business are we in?

Still on pressure pumping.

Let me answer that, Arun. It's Doug. We have another 38,000 horsepower still to be delivered between now and the end of the first quarter. That was all ordered by our existing business in the Appalachians. All of that equipment we're talking about here I think I said there was seven quints coming in Q4 and another nine in Q1. That all goes up into the Appalachians.

Let me speak to the contract issue. In our own business, we actually have no term contracts with Universal Well Service in the Appalachians. We are talking to some customers currently about term contracts, but to date, we have nothing signed. We did inherit a couple contracts, if you will, with the Key assets. We're currently evaluating and looking at how we go forward with those.

Okay. My last question. John, can you help us a little bit on the depreciation and tax line going forward as you have integrated Key? I just want to understand how you're going to depreciate the Key assets that you acquired.

I can't give you perfect clarity on that, but I'll give you what I can. As you know, when you do an acquisition like this, you do a full appraisal. We don't have the final results from that yet, so finalizing one will be with the property balance of the depreciation is still somewhat unclear. For our purposes, we viewed that it will probably come out to about $6 million to $8 million a quarter of depreciation for the existing business. Realize that's a bit of a wide range, but that's as close as I can (inaudible) say. I would also point out that the fourth quarter appreciation for the existing business is $85 million. Was a little higher than the normal run rate related to something -- we look at our yards, look at our equipment and at times retire things. There was some additional depreciation in the quarter related to that.

So, my expectation of the existing business is that the depreciation in the fourth quarter would be somewhere around $87 million. Then you would add to that $6 million to $8 million for the new business and that gave you range somewhere, $93 million to, maybe as high as $95 million. I realize that isn't perfect, but it's what I have today.

In terms of the tax rate, the current thought is it would be somewhere around 37% range. Maybe a little less than that. The other one I think I would comment on is the G&A side, it was a little bit higher this quarter than what we had seen in the second quarter, driven by a couple items that were just, I don't want to call them non-recurring; they are things that show up every now and then and that probably increased it [$250,000] and my belief today is that the new Key businesses will add somewhere $2.5 million to $3 million to our G&A line, which would bring you to an estimate of $15 million to $16 million of G&A in the fourth quarter.

Okay. That's very helpful. Thank you.

Your next question comes from the line of Robin Shoemaker from Citigroup. Please proceed.

Thank you. I wanted to ask generally about the kind of convergence of spot and term rates for equivalent rigs in various basins and how you look at the relative advantages of keeping certain rigs on spot where you might have an opportunity to go to term? Basically, your strategy around that is my question.

Robin, there certainly is convergence. I think we've talked about this before. How the price of new builds really almost dictates what happens in the rest of the market. As all the new builds and the high-quality rigs are tied up, certainly allows for this convergence for that next group of rigs. It's very hard to generalize. Because in the very hot markets today, places like Bakken and the Marcellus, those gaps have narrowed considerably so that we get very attractive rates on existing equipments coming out of the spot market in those markets. In markets such as west Texas, for example, where there's still a pretty good oversupply of rigs, one, there isn't a lot of new builds, so we don't really see much of a convergence in some of those kind of markets. So, there's a whole range of things in between, but generally, I would say we're seeing this convergence so that good quality FCRs are getting pretty close to the price of new builds. Then, as I think further proof, when we've signed some term contracts with mechanical rigs, we're very pleased with the pricing that we get on them.

Okay. A kind of related question. On the term contracts you're signing for the Apex rigs here recently, how does that compare to earlier this year when you kind of signed the first kind of round of long-term contracts? Are we generally talking a three year term here?

They are pretty much all three year. We have seen some people offering or willing to talk about longer terms, but typically they want a lower price for that guaranteed extra couple years. We have chosen, I think, to push the prices from the start of the year. Without giving you the numbers, they are pushing sort of 10% higher than where we were at the start of the year.

Okay. Excellent. That's my questions. Thanks.

Your next question comes from the line of John Daniel from Simmons & Company. Please proceed.

Hi. Just real quick on the 21 new rigs for 2011. How many of those are under contract?

John, I'd answer that this way. We're sold out. We have term contracts on all of the rigs through the end of the first quarter. I'm not sure I have that exact number in mind, but it's five rigs I guess of the 21 at this point that would be under term contracts. I will say this, we're in very final stages, I guess, of negotiations with some other customers. We do expect to sign further new-term contracts in Q4.

Okay. Cool. On the pressure pumping, a couple quick ones. The 29 pumps today with 16 to be delivered. When all of that's said and done, is that three or four frac spreads? I thought you were contemplating --

John, we are laughing. It initially started out, we thought, as four. But here's what's really happened to us in the Marcellus. The first horizontal frac spreads in the Marcellus really started out at 20,000 horsepower. So, that has now moved to 30,000 horsepower. So, it's just a definitional problem. We convince ourselves we have actually ordered four, but that four has now sort of converted itself into three. It's just the added horsepower requirements the customers are looking for to do the multiple stages and the much higher pressures and volumes that we're pumping.

It's good for us because obviously the greater the intensity, the more profitable is the work. This is not a problem, this is actually a good thing.

Fair enough. Might have to come back to you on that one. Quickly on Key. The assets, or rather the contracts that you inherited, can you tell us when those contracts expire?

There's really just one contract that I guess I would officially call a long-term contract. It expires in March of 2012. Is that right? I think I have got that date right. Really there's just the one, what I would call a term contract. There are some pricing agreements that I really wouldn't call a term contract.

Fair enough. Okay. Then just lastly for me. You said in the release you're contemplating new pressure pumping adds in 2011. Is it the quoting stage yet or have you placed any orders yet?

We have not placed any orders yet. There's the ongoing order for Universal for the Appalachian region, but there's nothing on order as yet for our newly acquired Key business. We're in discussions about that currently.

Okay. Thanks.

Your next question comes from the line of Alan Laws from BMO Capital Markets. Please proceed.

Good morning. I have quick, these are kind of scoping questions I guess, more strategic. When you look at your mix of business as an historical drilling company with a little bit of pumping, now more of a high-efficiency land driller with a growing fracturing business, kind of a national fracturing business, is there a target for how big you want each of those components to be?

I think the target is as profitable as they can possibly be. We have never been fans of big. We've always been fans of more profitable. So, the answer to that question is we think -- sort of exactly what I said before, which is that we think the strategy of being in these two gating businesses for the overall place of the Company is where we want to be. We see ourselves as growing both of these two businesses over the foreseeable future.

When you look at the fracturing business though, like you just mentioned, you ordered four fracs spreads; you're really getting three given the trends in frac spread size. Is there a point where you need to be a certain size of a company as number of spreads to be competitive? Basically, I'm asking is the barrier to be in the frac business much higher today than it was in the last cycle?

I think it is, Alan, just from the point of view of the cost and the amount of horsepower to build even the smallest frac spread to do a horizontal is pretty significant. It's well in excess of what a drilling rig costs. I think it precludes some of the moms and pops from really playing in the game, but I think we're already at a size that makes us a significant player. Certainly, I don't think -- I don't know that you need to be double the size just to be able to play.

Alan, what I would say, and frankly the questions are interesting that you are asking, and not the ones we have necessarily prepared for, but the interesting thing is both the drilling business and the fracing business have bifurcated. Where there is in effect, the new horizontal work and the conventional work, and in effect, the barriers on the horizontal work, whether both drilling or in fracing, are pretty significant because of the amount of intensity that those two businesses each require.

That's interesting. I appreciate that answer. The last thing here is when you're looking at your capital budget, I think you mentioned you're going to build another 20 or so land rigs next year and you talked about looking at your capital spend for pumping. Is M&A a factor still, or are you done for now?

I think M&A is always an opportunistic business. One which, when people speak about it as a planned company objective, you can make some stakes because then you are obliged to do certain things, or become obliged. I think M&A is always about seizing opportunities when they are presented and they fit with your strategy and when they are consistent with what you think the assets are worth. I feel as if on these calls we were asked for a couple years before we went forward with the acquisition of assets from Key. Why haven't you done a transaction and so on and so forth. We did a transaction when we found one that we thought was very attractive from our perspective.

Excellent. And you got it at quite a good price, I might add. That's all I've got. Thank you.

Your next question comes from the line of Geoff Kieburtz from Weeden Company. Please proceed.

Hi, Geoff. How are you?

Good morning. I'm fine. Not sure if I've ever heard that particular version. The pressure pumping, as I understand you haven't scoped out what exactly you want to do on the acquired assets. What do you think the lead time is to actually get something delivered today? If you put in an order today, when could you get the assets in the field?

Geoff, I think if we put in orders today we would probably take delivery of the assets in late March, April. We get them to the field a couple months later than that. I think by mid-year, you'd have some assets in the field.

You're in the kind of six to seven month lead time?

Correct.

All right.

Keep in mind, that's to take delivery. There's a couple months of transmissions, engines, pumps. We typically put some things together ourselves. You've got to marry a whole bunch of things together, just like you do on a drilling rig. Your deliveries might be six or seven months, but you probably still need a month or two to get it to the field.

Geoff, I also think that different people have different abilities to get things quickly or slowly. Doug's answer that he gave may not be an industry answer.

I understand. That lead time presumably has elongated over the last six or nine months?

And presumably will be elongating over time now as the world goes forward.

Sure. Okay. In terms -- do you have a target or a maximum in mind in terms of the number of drilling rigs that you would want to have on term contract?

I don't think we see a maximum or a minimum, frankly. What we've always felt on that score was that we would do the contracts, term contracts that is to say, when we thought the terms were advantageous for us and good for our customers, both. When we did, we've moved forward with it. The upswing in term contracts, I think, comes about from several factors. One is, in effect, the scarcity of the equipment that's needed for these new kinds of horizontal plays that we're talking about and we always said to people we had equipment that was highly desirable and I think the customers embracing of that by virtue of the increase in numbers of term contracts shows it. The second is that recognition that there's some scarcity in that market place of those kinds of rigs makes customers willing to pay prices for that equipment that we think is -- are fair for us. Therefore, both sides are happy to enter into term contracts.

But Mark, in that thought process, there has got to be some element of downside risk protection. My impression is that your broad commentary about the risk embedded in natural gas prices seems a little bit more comfortable than what we have heard from some of the other companies in the industry.

I think that these are risk-reward propositions always, Geoff. Frankly, one of the things that I think people are probably not noticing is the extent to which oil and oily liquids are parts of our business at this point and a significant part of our demand for rig fleet. On a revenue basis, during the last quarter, that was pretty much nearly 50%.

Okay.

The market is being driven by a lot of factors. That's why I said looking at outlook, we talk about sort of two things, shale plays and oil and liquids rich plays.

Broadly speaking, internal thinking right now, is at the end of 2011, is the US rig count going to be higher or lower than at the end of 2010?

Geoff, I leave those kind of calls for people like yourself.

I've made mine. I want to know yours.

My goal is to try to get it right for the next quarter.

Okay. Last question. John, you gave us various D&A, G&A and so on. Interest expense you got a few moving pieces in the quarter, what should we expect in interest expense in 4Q?

I think our total interest cost will approach $6 million. A portion of that is likely to be capitalized in conjunction with our construction activities. I think the net interest number would be somewhere between $4 million and $5 million.

Okay. And that's a decent run rate for 2011?

Yes, I think it would be. Obviously, the interest rates we're paying on the debt are great, quite frankly, at 4.97% on the fixed rate private placement goes out 10 years. Currently, LIBOR borrowings on the term loan are close to 3%. Just a great opportunity we find ourselves with in the quarter to put that on the balance sheet at rates that are just, really frankly, fantastic.

Great. Thank you very much.

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

Good morning, gentlemen.

Good morning.

Now I realize that you're always reluctant to put out rig forecasts beyond one quarter as we just heard, but I just want to get your thoughts on activity in the Permian basin where you do have a big presence and you highlighted the resurgence in activity there. We have heard Oxy state their intent to increase drilling in the play, Apache just picked up BP's assets. Could you hazard a guess in terms of step up in activity we could see in the Permian heading into 2011?

Scott, there's a lot of people throwing numbers around. I guess we're not going to join the fray in throwing out a number. We hear a lot of talk. So far, we haven't seen huge indications. It's been nice, slow, steady growth out there. I guess we're going to take a wait and see attitude.

Our position is we're very well positioned there. We've got a number of rigs that can go back to work. We have really -- west Texas I think is up almost 15 rigs from the start of the year. We certainly have the capability to continually expand that fleet out there and take advantage of those opportunities as they develop. But I'm not going to hazard a guess and say -- I have people say there could be 200 or 300 rigs working out there. Pick a number.

Frankly from my perspective, Scott, it's interesting. Years ago Patterson had the number one market share position in west Texas. UTI had the number one market share position -- or number two market position in that market place. When they merged, obviously, we were a very strong player in that market place. From kind of 2001 through this year, that market place has really seen very little operations from the major players. It's been very much a smaller operators play. Where we have seen these transactions, we've been encouraged by the prospects that affect the larger E&P companies are going to go to work in that market place. Realizing our capability and our historic position in that market, we're pretty encouraged by it. But giving you a number would be making it up. Because we have no visibility of it.

That's understandable. But to pry a little bit more, based upon the conversations you're having with your customers, would you say the outlook is for a healthy growth rate into 2011? Are you hearing clear indications of the demand for more rigs in that play?

There's certainly indications that there's more demand in the play. At this point, I just couldn't tell you whether it's 10 rigs or 50 rigs. We really don't know. But there's certainly a lot of people talking, and it's getting a lot of attention, both in the press. You can just sense that there's a lot of people looking at doing things.

Okay. And if I could, turning to Canada. You have a small rig fleet there. I believe a little bit smaller horsepower-type rigs in that play. What's your outlook for Canadian activity as operators there look to do more horizontal drilling, more complex drilling? Would you look to put Apex rigs into Canada?

Can I clear up a little bit of a misconception to start with. Our rig fleet there is actually pretty broadly based. But it's actually, for that market, it's probably slightly higher horsepower than the average contractor in Canada. We do have some small rigs, but they haven't worked up there in the last three years. I think last Winter we got up to 16 rigs and the bulk of those 16 are kind of 1,000 horsepower and greater. I think we're actually very well positioned for some of the pending shale plays there.

To answer the second part of your question, we have had numerous customers that work on both sides of the border very interested in some of our Apex walking rig technology. The difficulty we have seen to this point is that Canadian market typically works for nine months of the year. We look for returns to our shareholders based on the 365-day operating performance we can get in the US. So, typically, I think if you looked at it, there's far less term contracts in Canada. The customers there still have this mentality that it's a nine month business. We just haven't seen the kind of returns. We think ultimately, quite frankly, I think people when they see the improvements in the technology, I think were quite prepared to put those rigs in there, but they better get at least an equal return or better return than we get in the US.

Okay. That makes sense. I'll turn it back. Thanks.

Your next question comes from the line of Scott Burk from Oppenheimer. Please proceed.

Good morning. I just had a couple of follow up questions here. I wanted to go back to the discussion on day rates for the Apex rigs. Just wondered how they compare to the average rates you're getting of around $18,000 a day?

You're talking about on the new builds?

Yes. The new builds.

They are certainly higher than the $18,000. I guess we really don't want to get into specific day rates. We have given you some information in the past on where we think new build prices are. Some of our existing Apex rigs really are still new rigs. So they have certainly -- when we talked about closing the gap or narrowing that gap, they are certainly higher than the $18,000 a day average that we see. You got to remember that based on that average, we have rigs working in west Texas that are significantly below that $18,000 average. You have got to have some that are well into the mid-20s or higher to get those averages.

Okay. All right. Thanks for that color. Along those lines, I assume you take some kind of a discount to do a three year term contract versus just putting it on a spot contract, what kind of spread do you see there?

I don't think we think about it that way at all. Frankly, what we say is how much are we going to get paid? What's the margin that we expect from the particular contract? Frankly, the thinking that the line you're going along is way too narrow and not nearly broad enough in terms of the way we would approach it because different markets have different costs, different equipment is required in different markets. There's a whole series of additional considerations beyond just price one and price two. We don't think about the way you're posing the question. We say to ourselves is the overall contract, in light of all the risks and returns, something we want to do.

Okay.

I think the reason the customer is doing the term contract is because they have known drilling needs. They are trying to lock up a specific rig for a period of time to meet those needs because If they don't, that rig could move to another customer. I don't think we discount for long-term contracts. I think it's the customer wanting to know they have the rig available for one, two, three years. Whatever it might be.

Yes, and kind of the implication, what you're talking about is basically lowering the risk for you from your perspective as well.

It lowers the risk for both parties.

We have locked in cash flow, and they know they have the rig they want to get the work done that they need to get done.

Okay. I had one question on the pressure pumping side. You had a nice expansion in the pressure pumping revenues and margins for the quarter, 16% for the quarter as you mentioned. Can you say is this driven more by price improvements or was it driven more by additional stages per fracture?

I would say generally, it's a mixture of activity and price. As I mentioned to you, for example, on the big Marcellus horizontal fracs, we did 10 more in the quarter than we did the prior quarter. I would also say there's been a very nice impact from the price per stage. The average number of stages that we completed has stayed relatively constant in the eight to 10 stages per well.

Okay, good. Thanks.

Your next question comes from the line of Andrea Sharkey from Gabelli Company. Please proceed.

Hi. Good morning. Thank you for taking my question. Ill I will try to make this quick. Most of my questions were answered. I was wondering if you could maybe comment on -- I know you haven't really seen a slow down in maybe the gas direct activity and you're strong in the oil directive, so that, obviously, will be a positive for you, but would there be a change if you would have to move your rigs that are drilling for gas into the oil or liquid space in terms of pricing and margins and things we should think about if there's a sort of a blip say mid-2011, back half of 2011?

I guess my answer to that question, Andrea, is that I don't think that the pricing of rigs is terribly dependent on whether it's drilling for oil or for natural gas. From our perspective, subject to winterization issues and things of that sort, I don't see that the costs from our perspective are different whether it's oil or natural gas. There are different costs in different regions. There are of course the costs of, for example, winterization, but by and large, there's not a difference in either the revenue side or the cost side between the drilling for natural gas and the drilling for oil. The costs and the revenue side differences tend to be about regions.

That makes sense. Maybe that's what I was trying to get at, if you see less work in say the Haynesville and more work in the Permian where the margins are lower and that sort of thing. But I guess it wouldn't really be the same rigs working in the same region.

I depends on -- I thought that's what you were thinking about. I was trying to, by virtue of the comments I was making, suggest that to the extent it was moving to the Bakken or Eagle Ford or other possibilities, you could get very different results. Frankly, in the Permian, if in fact we see a real upswing in programs from majors to drill large numbers of incremental wells that we think we would see some corresponding change in the pricing for that market place, I don't accept the premise of the question, which is in effect lower prices are going to be true in the Permian than the are going to be in some other areas assuming there's this movement towards more oil drilling.

Okay. That makes sense. Maybe just to talk about the Marcellus, both from the drilling and the pressure pumping side. Have you seen any shift in the competitive landscape? I think there's been some commentary from one of your larger competitor that they are finally starting to making some in roads there and are they being aggressive on things like pricing or anything that is really having an impact, or you expect could have an impact on your business there?

I don't really think anything has changed. We have known really for the last year and a half that, that market is growing exponentially. In both segments of the business, we have seen competitors move into that market place. I think it's just been an ongoing evolution, both on the drilling side and the pressure pumping side. It's a very active, growing market. Obviously, there's opportunities there for more than just the people that are well established. It doesn't surprise me that we get additional people coming in to compete in the market.

Okay. That makes sense. Maybe one last one on the Appalachian region. We were starting to hear some E&Ps talk about different plays like the Utica and the Upper Devonian. I know it's still probably very early days on that stuff, but as far as you know, would that use the same equipment that is targeting the Marcellus, would the Upper Devonian be shallower maybe use some of your lower horsepower rigs? Is there anything you can tell us about that?

I think it's a little bit all over the map. I think it's a little too early to be making those projections. What I would say is we're in very different positions there with our long established history there. We've been there for 30 years in the pressure pumping business. We're well prepared for the full range of types of wells that are going to get drilled and completed up there. But I think it's too early to say is different equipment going to be required. Just like almost every other segment of whether it's the Haynesville, or the Eagle Ford or the Barnett, over time things have changed. People have zeroed in on what's the exact equipment, both pressure pumping and drilling, that they are looking for. I fully expect the same thing is going to happen up there, but I think either way in both segments of the business, we're very well positioned to cover whatever happens.

Okay. Great. Thanks so much.

Your next question comes from the line of Jud Bailey from Jefferies. Please proceed.

Thanks. Good morning. Most of my questions have been answered. I wanted to follow up on one issue. I apologize if you gave this already or I missed it. The contract break out or the contract coverage for next year, 65 rigs, average rigs I believe. Did you give a break out of how many those are mechanical versus your Apex and higher end SCR rigs?

We did not on the total for the year. We gave you a break out on the newly signed contracts during the quarter. I don't have that information in front of me.

The only thing I think we can tell you is just what we did last quarter, which is what we did in the call already.

Okay.

I wouldn't go any further than that.

It's probably, I would assume a substantial number is Apex and SCR is what I would assume.

That's correct, yes.

Then just circling back one more time on the Permian. You touched on this already, but there seems to be -- that market is much looser in terms of availability. Historically, you have not really ever activated equipment. You have chosen to keep them off the market until prices start to move higher. It's safe to assume that's probably your strategy going forward or are you more apt to reactivate rigs at lower margins? Or do you want to see pricing move up a little higher from where we are today in that market?

I think we're feeling that pricing in that market will need to move up for us to be very anxious to activate additional rigs in that market place. With that said, to the extent to which programs from major players start to come in there, there becomes greater demand going forward, then we would expect pricing to move correspondingly and we think we would be extremely well positioned to take advantage of that.

One of the issues we have seen out there, a lot of that work tends to be one or two wells at a time. It's sort of what I would I call non-program type work. For us to bring a rig or activate a rig that's been down for some period of time, it's very difficult to do that in today's current pricing environment just to go drill a 20-day well.

Sure.

I think over time, I think we will see a little bit more and more program type work up there. Typically, that's been a spot-market business where there aren't a lot of term contracts. But I think as the market improves, we will see both some more program drilling and maybe the potential for some term contracts in that market.

Okay. Great. My last question on your new Apex rigs for delivery in 2011. Did you give an approximate cost for construction relative to the ones you ordered earlier in the year?

We did not, but the number hasn't substantially changed. We still think and plan for approximately $18 million per rig.

Okay. Great. Thanks for taking the questions.

(Operator Instructions) At this time, Mr. Siegel, I am showing we have no further questions. Back over to you for closing remarks.

Just want to thank everyone for their participation in the call. Look forward to our next call. Thank you very much.

Ladies and gentlemen, thank you for your participation in today's conference call. You may now disconnect. Have a wonderful day.