Patterson-UTI Energy Inc (PTEN) 2011 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first quarter 2011 Patterson-UTI Energy Incorporated earnings conference call. My name is Tom, and I will be your coordinator for today. At this time all participants are in listen-only mode. We will be conducting a question-and-answer Session towards the end of today's conference. (Operator Instructions) I would now like to turn the presentation over to Geoff Lloyd on behalf of Patterson-UTI Energy. Please proceed.

Thank you, Tom. Good morning, and on behalf of Patterson-UTI Energy I would like to welcome you to today's conference call to discuss the results of the three months ended March 31, 2011. 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 global economic conditions, decline in oil and natural gas prices that could adversely effect demand for the Company's services and their associated effect on rates, utilization margins and planned capital expenditures, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating acquisitions, shortages of equipment and materials, government regulations, 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 and through the SEC 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 and in the Company's press release issued prior to this conference call. Now it is my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark.

Thanks, Geoff. Good morning, and welcome to Patterson-UTI conference call for first quarter 2011. We are pleased that you are able to join us this morning.

As is customary, I will start by briefly reviewing the financial results for the quarter ended March 31, 2011. I will then turn the call over to Doug Wall, Patterson-UTI President and CEO, who will make some detailed comments on each segment's results, as well as sharing some operational highlights for the quarter. After Doug's comments I will share a few brief thoughts on general market conditions. As usual, following our prepared remarks, we will take your questions. At the outset let me say that we were very pleased with our results during the first quarter. Simply put, both our drilling and pressure pumping businesses performed well with substantial sequential improvements in revenues and profitability, despite the hindrance of some unusually harsh winter weather in some of our prime geographic markets.

As set forth in our earnings Press Release issued this morning before market opening, we reported net income of $71.3 million, or $0.46 per share, for the three month period ended March 31, 2011. This compares to net income of $4.2 million, or $0.03 per share, for the comparable period in 2010. Revenues for the quarter were $567 million compared to $272 million in the same quarter last year, an increase of $295 million, or more than double. On a sequential basis total Company revenue improved by $62 million, or approximately 12%. Similarly, on a sequential basis revenue growth in drilling improved by $37 million, or approximately 11%, and revenues in pressure pumping improved by $23 million, or approximately 15%. EBITDA for the quarter improved to $213 million, which represented a $24 million improvement over the preceding quarter.

Our Company's achievements in the first quarter reflect seven consecutive quarters of growth in EBITDA driven by our two core businesses. As I said at the outset, weather did hinder our results. We believe our revenue in pressure pumping would have been approximately $8 million higher absent the unusually harsh weather. I doubt anyone who experienced it has forgotten the snow and ice storms in north Texas and the late winter heavy snowfalls in Appalachia, all of which affected our businesses.

For the quarter capital expenditures were $181 million. Most of this CapEx relates to our APEX rig new build program and during the quarter we received substantial rig components as we begin to accelerate new rig production. We completed three rigs during the quarter, two additional so far in April, and another rig is expected to be completed this week. Accordingly, we expect to have six new rigs completed through April and we expect to hit our target of 25 new rigs for the year. With respect to our drilling business, we have now witnessed through March; 21 months of consecutive growth in our US rig count and the uptrend in US rig count has continued through April to date. We think this continued increase in active rigs demonstrates that our diverse rig fleet, both new, advanced technology rigs, as well as our strong base of conventional rigs, is important for satisfying our customers overall needs in many different markets.

Strong crude oil prices continue to drive much of the activity increase, and we, with our rig and geographic diversity, have been able to improve our share of this rebounded market, particularly in areas such as West Texas and the Bakken. Currently, approximately half of our active rigs are drilling primarily for oil and liquids and we expect to put additional rigs to work in the Permian and Mid-Continent over the course of the summer months.

Our pressure pumping business had another good quarter. In terms of expectations, we said on our last call we expected revenues for the pressure pumping business to be in the range of $170 million to $180 million, and we reached the high-end of that range despite the weather hindrance. Prices for our service have continued to increase, and we are extremely optimistic about this business going forward, particularly as we take delivery of the additional equipment we have on order. Most noteworthy, pressure pumping in the first quarter was 32% of our revenue and 27% of our EBITDA, as compared to 20% and 14%, respectively, one year ago.

As we see at Patterson-UTI, our progress and respect of our strategic plans for our business should be measured by our operational and financial results. Our operational and financial results show that we are achieving improving results both on a year-over-year basis and on a sequential quarterly basis. These improvements have come over a number of quarters and have come as a result of a number of achievements. Our new APEX rigs have dramatically added to what we are able to offer for our customers. At the same time we have built on our traditional strengths and improved our conventional rig fleet. In pressure pumping we have doubled our business through acquisition but at the same time grown our existing business organically.

We have invested substantially in our people in both our drilling and pressure pumping segments. The improved operating results we have achieved demonstrates the transformation that has occurred at Patterson-UTI. Likewise, we are pleased that the market appears to be noticing the pronounced period of improvement in our equipment, operations, and financial results. I would now like to turn the call over to Doug, who will further discuss our operations for the quarter.

Thanks, Mark. Once again I am going to start this morning with some commentary on the drilling company followed by some comments on pressure pumping. First with drilling, for the quarter ended March 31, 2011, the Company had an average of 207 drilling rigs operating, including 192 in the US and 15 rigs in Canada. This was a ten-rig increase in the US, or approximately 5%, over the average activity levels we experienced in the fourth quarter. The overall industry land rig count in the US increased by approximately 2.7% during the quarter. So, once again, we feel we gained some added traction and share in the marketplace.

Perhaps the most pleasing change in the quarter came on the pricing front. Rig pricing continued to improve, with significant price increases in certain geographic markets primarily driven by oil. By rig class, we were very pleased with our ability to increase pricing with our conventional rigs and feel this is still the area with the most upside potential. Obviously, the increasing demand for rigs destined for the oily basins, particularly such as the Bakken in West Texas, has helped to improve our over all pricing, but has also caused some increase in daily operating costs as labor availability in these markets remains tight.

We still have additional rig capacity capable of going back to work in many regions, particularly West Texas, Mid-Con and the Rockies. Overall, we believe we are very well positioned to benefit from any further incremental demand in the liquids rich and oily basins of the US. We continue to see strong customer interest in our high quality conventional rigs and expect to see additional demand in this area in the coming months.

So let me turn to numbers for the quarter. Average revenues per operating day during the first quarter were $20,240, compared to $19,090 in the fourth quarter, an improvement of $1,150 per day. Average direct cost per operating day increased $730 to $11,730 for the quarter, compared to $11,000 last quarter. Daily drilling margins increased by $430 per day during the quarter to $8,510. Revenue per day grew slightly more than we expected but, as I mentioned before, so did our costs. Our US daily rig costs were up approximately $630 per day, primarily due to labor increases and increases in other operating costs such as fuel and repairs and maintenance.

Canada is now well into spring breakup with only two rigs currently working. We expect to average two rigs drilling during the quarter. In the US, we now expect to average approximately 200 rigs operating for the second quarter. We expect US average revenue per day to increase by $600 to $700, and US daily margins to increase by approximately $400. However, due to the seasonal decline in Canadian activity, the overall Company average revenue per day is expected to increase by about $200 and the overall daily margins by approximately $250. Looked at from another perspective, increases in US rig count and daily margins are expected to more than offset the approximately $13 million sequential decline in the Canadian drilling margins due to spring breakup.

With respect to term contracts, I'm pleased to say we made excellent progress in the first quarter by signing up an additional 18 term contracts, including nine APEX rigs and nine conventional rigs. Based on contracts currently in place, we now expect to have an average of 102 rigs working under term contracts for the remainder of 2011, as compared to the 86 working under term contracts in the first quarter.

I would now like to give you a quick recap of our new build program. Of the six rigs that Mark mentioned earlier, that we will have completed through April, five are APEX walking rigs and one is an APEX 1500. Four of these rigs will operate in the Marcellus, one in the Eagle Ford, and one in the Permian. All of these rigs are on three-year contracts. In addition to the 25 new rigs expected to complete in 2011, we expect to build a similar number of new rigs in 2012. We currently have term contracts signed for 18 of these rigs and expect to sign an additional seven contracts in the very near future.

That includes my remarks on drilling, so let me turn now and make a few comments on our Pressure Pumping business. Revenues in our Pressure Pumping business totaled $180 million for the quarter. As Mark said, at the high-end of our expectations. We believe that weather probably cost us somewhere in the order of $8 million in revenue for the quarter. EBITDA for the quarter for pressure pumping totaled almost $57 million. Let me make a few comments on both of our operating regions. We are extremely pleased with the performance from our recently acquired pressure pumping business in Texas. Revenues and operating profits were better than we had forecast, as demand in pricing continues to remain strong in the Texas market.

In terms of pricing, frack discounts improved by a couple percentage points during the quarter and we expect this trend to continue over the second quarter. Currently we have approximately half of our total frack horsepower in the East Texas markets. Although we did not add any new equipment to this marketplace during Q1, we are pleased to report that we expect to have approximately 35,000 additional horsepower in the field by the end of May. We are planning to deploy this new equipment in the Eagle Ford and expect it to be highly utilized at attractive margins. Our second new frack spread is still on track for delivery later in the year.

One operational highlight I would like to share with you this morning -- in the Eagle Ford. Our largest frack crew in the Company operating for a major operator set several new field records during the quarter. Firstly, shortest pump time on a three well pad, shortest cycle time at 4.5 hours per stage, and the first crew in this field to complete six stages in a 24 hour period. These achievements are significant and a testament to our operational capabilities. My thanks go out to all of the crews and supervisors involved in this project.

Turning now to the Appalachian. Despite days lost to weather, we still had a record-setting revenue quarter for this region. Overall frack revenues were up almost 27% from quarter-to-quarter, reflecting the importance of the horizontal shale fracks. During the quarter we added 11,000 horsepower of new equipment which allowed us to fully complete an additional quint frack spread in the Marcellus. We now have a total of 45 quint in service in this region and expect delivery of an additional 75,000 horsepower to be deployed during the last four months of the year. Obviously, we continue to be very encouraged by the ramp-up in industry activity in both the Texas and Appalachian markets. We feel we are very well positioned in both of these markets. We are currently expanding our facilities in south Texas, which houses our Eagle Ford operations. As this market continues to grow we expect to see further efficiencies in our operations by placing our crews, materials, and equipment in closer proximity to the work.

Before turning the call back to Mark, let me make a comment or two on our expectations for our pressure pumping business for 2011. As mentioned previously, we have approximately 204,000 additional horsepower coming to market this year. We expect to end 2011 with approximately 650,000 horsepower in pressure pumping, and we anticipate adding additional orders for equipment beyond these numbers for delivery in 2012. We do not expect over capacity issues in the near term, and I think that replacement cycles, shorter equipment life and increasing service intensity will continue to balance the supply and demand forces in this segment. With respect to the second quarter, we expect our revenue to further increase by approximately 10% or so, with some improvement in margins as well. With that I will turn the call back to Mark for some concluding remarks.

Thanks, Doug. As I said at the outset, we are very pleased with the operating and financial results for the quarter as well as the tremendous progress we have made on a number of strategic fronts. Our management team believes that Patterson-UTI has achieved a significant transformation and is poised for continued growth. We remain bullish about the prospects for the energy business in North America. $100 oil is driving a shift towards more drilling in high liquids and oily basins, and we are well positioned in both of our core businesses to take advantage of this trend which we believe is long-term.

We are pleased that increases in drilling for oil and liquids-rich gas has caused Patterson-UTI rig count to continue to rise despite the reduction in natural gas drilling. At the same time, we remain convinced that natural gas drilling in North America will increase over the long-term. Ironically low natural gas prices are causing industrial users and policy makers to take a second look at natural gas as a source of dependable, low-cost and environmentally-friendly fuel. Moreover, world events -- the sad earthquake in Japan and the political unrest in the Middle East -- underscore the timeliness of this insight. We believe that these long-term trends will ultimately boost demand for North American natural gas and Patterson-UTI is uniquely well positioned to benefit from this long-term trend. Moreover, recent M&A transactions for a company that provides drilling services and a company that provides pressure pumping services highlight the value of the assets that Patterson-UTI holds. Our operating success underscores our ability to use these assets effectively for both our customers and our shareholders.

All in all we're very optimistic about both of our businesses going forward. The stage has been set for the next step upwards. In closing this morning, I'm pleased to announce that today the Company declared a quarterly cash dividend on its common stock of $0.05 per share, to be paid on June 30, 2011, to holders of record as of June 15, 2011. In closing, I'd like to take a moment to thank, personally and on behalf of our entire management team, our 7,000-plus colleagues who make Patterson-UTI the Company that we are. We have a talented and dedicated workforce and we salute and thank you for your service. Please know how proud we are of what you do. Thank you. At this point we would like to open the call for questions.

(Operator Instructions) Your first question comes from the line of Christopher Butschek with Raymond James. Please proceed.

Hey guys. Congrats on the great quarter. Some of the other pressure pumpers have mentioned that they see the market remaining under-supplied well into 2011, and maybe even 2012. Regardless of the emerging growth in 2Q, how do you see the back half of the year shaking out?

We're pretty optimistic. I must say, I couldn't hear the beginning of the question. Could you repeat it, please?

Of course. Can you hear me a little bit better now?

Perfect.

I was asking that some of the other pressure pumpers see the market remaining under-supplied well in 2011, and some have even mentioned 2012. You're talking about growth in 2Q. In the margins, how do you see the back half of the year playing out?

We think the back half will be very strong. As you know, a lot of the equipment that we have on order is coming in the back half of the year. We do see both increases in activity. Our own revenue and margins continues to increase.

Okay. Good. If I could switch gears a little bit. Moving to land drilling, I wanted to make sure I heard right -- 25 rigs in '11, another 25 in '12, and 18 of those are already under contract, is that correct?

18 of the first -- of the 25 that we were putting out this year are already under contract with commitments for an additional seven. So in effect all of the 25 that we are putting out in 2012, we either have signed contracts for or very significant commitments.

Very good. I will turn it back.

Your next question comes from the line of Joe Hill with Tudor, Pickering Holt. Please proceed.

Good morning.

Good morning, Joe.

Guys, in terms of the cost of the incremental rig, relative to the cost of the incremental spread, I was thinking an APEX rig was going to run around $17 million and the spread was around $1,000 per horse, but I would suspect we're seeing some cost inflation in each of those. Can you give us an update on what those look like today?

Joe, the rigs are probably in the order of $18 million to $19 million depending on which market they're going. If they're going to the Marcellus or the Bakken there's the additional winterize costs. There's a slight difference in cost between Walking rigs and APEX 1500s. But for all intents and purposes, if you use $18 million, $19 million, you're certainly in the ballpark. We would probably agree with you on the cost, the $1,000 per horsepower. So, we try to talk per horsepower as opposed to spreads, because it really depends where -- those spreads, as you know, are very different depending on which market they're going to. And if you took the $1,000 per horsepower, I think that's pretty realistic.

Our costs are pretty much locked in at the moment with our suppliers on the drilling rig side. We haven't firmed up all our commitments, obviously, into 2012. There's no question that there's some price increase that we're seeing on, really, pressure pumping equipment more than anything. We still feel pretty confident at the $1,000 per horsepower.

Okay. Doug, with regards to your ability to pass through cost increases under the term contracts, I assume you have those pass-through in place in the contract terms?

That's correct, yes.

We saw an $1,100 roughly quarter-on-quarter increase in day rate 4Q to 1Q. Can you give me an idea as to how much of that revenue increase was passed through as opposed to growth?

Joe, I don't have that number on the top of my head. Most of the increases you see on the drilling side are primarily labor. That was probably $400 dollars to $500 dollars per day, but it only occurred in two or three of those markets that impacted this quarter. I don't know, John, do you have any further color?

In addition what you said, I think the cost to trucking has gone up some and that's impacting our average daily costs. Just labor being tight, repair maintenance costs are a bit higher, too, and that's all contributing to the increase in costs during the quarter.

Okay. And then finally what are you seeing in terms of pipe availability for rigs and just fighting the trend of perhaps wearing the pipe out a bit more quickly in some of this horizontal drilling and going through the new build process and maybe things getting a little bit tighter in steel?

There is probably some debate as to whether the pipe wears out faster or not. In fact, in some cases it wears out slower. I think the big change that we have seen over the years is the move away from 4-inch and 4.5-inch to 5-inch pipe. So there is no question that we will be buying 5-inch drill pipe in the coming years. And drill pipe -- there is no question drill pipe costs are moving because of the price of steel. We have all of our 2011 pipe commitments locked in at a price, so we don't see -- we don't think we'll see any big inflation in drill pipe costs at least in 2011.

Okay. And just in terms of total feet per rig that you guys are looking at, is it around 18,000 feet, 20,000 feet?

Probably doesn't average that much, but certainly on the new builds that's what we're looking at is 18,000 feet to 20,000 feet.

Okay. Fair enough. Good quarter. Thanks, guys.

Thank you.

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

Good quarter. Just a couple questions. You mentioned the exiting '11 with 650,000 horsepower, Is that all hydraulic frack horsepower, or does that include the other stuff?

John, there is about 4,000 of cement horsepower included in that number.

Okay. So, then, sounds like then you are increasing the frack horsepower that you are getting in 2011. As I recall, you are going to exit '11 around 540,000 horsepower?

Sorry, John, can we go back to your first -- did you ask me if the total 650,000 was all hydraulic frack horsepower?

I was just asking, of that 650,000 how much is hydraulic frack horsepower versus nitrogen, cementing, acidizing, all the other stuff that might be sometimes called horsepower?

Yes. John, I haven't got that number in front of me. Before the end of the call we'll get back to you and give you that number.

Okay. Cool. As we think about the Q3 cash margins, all else being equal, does it go up $300 to $400 just by virtue of Canada coming back online?

John, do you want to take that? The question is, how much Canada will improve it in the third and fourth quarter.

All else being equal.

It would certainly contribute to margin. We don't run as many rigs in the third quarter as we do in the first, and we don't run quite as much equipment. That certainly would help margins up from the second and third quarter sequentially.

Fine. Can we get from you the quarterly contract schedule for the drilling rig business for '11 and '12?

John, we don't provide that level of granularity.

All right. Fair enough. Last one for me. You mentioned -- you cited the transaction value in a recent M&A deal. Is that what about what you would have paid for those rigs?

We're always in the market to consider what opportunities there are, John.

Okay. Fair enough. Thanks. Good quarter.

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

Good morning. The other signed contracts on the conventional rigs seems to be picking up, you noted nine new contracts. What were the rates on those conventional rig contracts relative to the current spot, and what type of term were you able to secure?

John, those contracts, as you know by definition, are all in excess of a year. There is a real mixture there. There's some 18-month contracts. There's some two-year contracts. We don't specifically get into rate-by-rate discussions on those contracts, but they were rates we were very happy with to lock in for those periods of time. In my mind they are current or slightly better rates than what you would typically get in those particular markets.

Great. And are we seeing more -- are we seeing greater rate inflation for the conventional units, not the Permians coming back for the high-end units which have obviously been moving for the past 18 months or so?

Yes. I would say that market, and some of those markets that we've seen greater percentage increases, but you have to remember they started from a much lower base to start with. We still feel that's where there is probably the most upside for further price improvements. I think one of the things, as we get more and more term contracts, we have to recognize that when you sign those term contracts you are pretty much locked in at those prices for some period of time.

Right. And where is the spot market rate for a 750-horsepower rig going to work in the Permian?

Well, there is probably not a lot of 750-horsepower rigs still going back to work in the Permian. But, again, I'm not sure I want to get that specific, but I would say on average those today are kind of in the $14,000 to $16,000 a day range.

Okay. And what level of labor cost inflation are you planning for in '11?

We have now increased our wages in every region in which we operate. At this point we don't anticipate further movements, or we certainly hope we don't see a whole lot of further movements before the end of the year. On average those labor cost increases equate to approximately $500 a day.

Okay. Great. That's all I had. Thanks.

Your next question comes from the line of Luke Lemoine with Capital One Southcoast. Please proceed.

Good morning. Doug, you have a large number of mechanical rig that is could possibly go back to work. Just trying to get an idea of how many of these are economically viable to put back into the field, if you could secured maybe one to two-year contracts where you could recoup your refurbishing costs?

Yes, Luke, we think about it. We're virtually sold out of 1,500-horsepower rigs throughout the Company. We have approximately today 30-some 1,000-horsepower rigs spread out again throughout the Company, some in west Texas, certainly and some in the Barnett. I think it varies greatly at this point, probably at least half of those could go back to work with little or no major capital spent on them. And then you get to the point that you got to look at them almost rig by rig to determine how much you'd have to spend versus what's the upside in terms of the length of the contract and the price. But we certainly have a number of rigs and we're pretty confident that -- I threw out numbers there, I think if you looked at the number of rigs below 1,000-horsepower, we probably have at least an equal number that I quoted in the 1,000-horsepower range that we expect fully capable of going back to work with little amounts of capital involved to put them back to work.

That's helpful. John, could you help us out with a little on G&A and D&A for Q2?

Yes. Terms of depreciation and amortization, we expect it to be approximately $100 million across the various businesses. And the G&A we expect would continue at a similar rate at around $16 million. And, also, tax rate I would expect to continue at around 37.2%.

Okay. That's it for me. Thanks.

Your next question comes from the line of Jim Crandell with Dahlman Rose. Please proceed.

Good morning.

Good morning, Jim.

First question. On your Rig business -- your APEX rigs, Doug, can you talk about three specific things? I have the performance of those rigs you think relative to the competition, the price you're getting for those rigs versus your competition for let's say similar type rigs, and how you're being awarded business in the field? Are you being awarded based more on negotiations, or are you bidding on most of the jobs for the new rigs that you put to work?

Jim, let me answer the last question first. We pretty much bid on virtually all of these new builds. There is basically three or four people with the capability and the capacity in the pipeline for new builds. I think in most cases all three or four of us get to bid on these projects. Obviously, some of us have some customer loyalties and there are some preferences in the business. But I think, for the most part, they're not just typically negotiated deals. Certainly we lose as many as we get. So I'm assuming that the other guys are in the same boat. In terms of performance, we've said before, we're delighted with the performance of our new rigs. I am not going to blow smoke and quote you a bunch of field records and that sort of thing, but I think the fact we've had such market acceptance with our new technology that I think proves the point our performance is as good as or better than anybody else in the marketplace.

I can quote you places where certainly we've had record performance. But I think our customers vote with their wallets, and if we weren't getting the kind of performance that the customer was looking for, I don't think we would be in the game. So I think that's all I'm going to say on the performance. I would stack our performance up against anybody's. And I would point out that it is not just the rigs, as you know, Jim, it's the people and quality of service and your whole culture around providing quality service that's incredibly important, and we place a lot of pride in that.

Do you think the Patterson -- A, that the good Patterson name and the quality of service, can that offset in most customer's minds, let's say the bigger drillers, the bigger operating companies who have been used to using other company's rigs for longer, meaning that other companies got into sort of the fit-for-purpose rigs for shale earlier than you did? Do you think you have been able to sort of offset that advantage, and that because of your strength that you're sort of fully competitive with most of the major operators?

Jim, actually, I would quarrel a little bit with your comment in your starting point. Because, actually, our walking rigs technology, which we started out in the Rockies, was among the very first of the really fit-for-purpose rigs that anybody built. So, first comment is that quite frankly I think we got into it. I think some other people got into it maybe with greater numbers, but we were in it pretty early and built some of the most advanced-technology rigs anybody built. I think that the customers perhaps in effect Main Street, have a greater appreciation of our rig capability I think sometimes than does Wall Street, frankly. So I think that there is a part of the question I am not sure is true in the street, in Main Street that is, in terms of acceptance of our equipment and acceptance of our capability. I think there is a much greater acceptance than is commonly perceived.

It turns out that our rigs are often featured in all kinds of places that I don't think are sort of customarily expected or maybe even appreciated. So to amplify on what Doug is saying, I think our performance stacks up against any of our competitors' performance. I think that our customers know and respect that. I think the increasing number of term contracts that we're able to achieve really reflects the fact that we've got tremendous customer acceptance of our equipment. And in terms of pricing, I think we're comparably priced to our competitors and to the marketplace.

Okay. That's helpful.

I don't think our customers would led us get away with anything more than the market, and I think we're pretty much not willing to take anything less than the market.

One question about pressure pumping. Do you think in both of major areas that you operate, that we are past the time now of the rapid ramp-up in price and that pricing is likely -- pricing improvement, just given all the capacity coming on from a number of different companies, is likely to be slow from here?

Jim, I think we're going to continue to see improved margins in this business as the market remains tight. I do think that over time -- we've got our costs going up, and I think we have all under estimated the costs of fuel and the impact that, that's got on things. So, certainly we're going to see continued improvement in pricing. It may be at a somewhat slower price, but until the market sorts itself out, I do believe that there is further movement on the pricing side.

Good. Okay. Thank you for the answers.

John Daniel, I'm not sure if you are still on the call, but let me try and give you some numbers on the question you asked earlier regarding our frack horsepower versus other. At the end of the year 12-31-10 we had approximately 355,000 horsepower frack capability. Approximately 82,000 other. By the end of 12-31-11, and this relates to the 650,000 horsepower we talked about, we will have approximately 555,000 frack horsepower and approximately 90,000 of other. Operator, next question.

Your next question comes from the line of Waqar Syed with Macquarie Capital. Please proceed.

Thank you for the information so far. Just a follow-up on your capacity numbers. Can you giver the number at the end of the quarter, both frack horsepower and others?

At the end of Q1?

Yes.

End of Q1 we really only added the 11 pumps, so the numbers would have been roughly 375,000 in frack and really we didn't add any other. So if you took the roughly 450,000 we had at the end of the year, you could probably call that 470,000.

Okay. One thing we noticed was, in the pressure pumping side that the number of jobs, fracking jobs, declined between the fourth quarter and the first quarter, while your revenue per job went up quite sharply. Is the decline in the number of jobs a function of the weather impact? Or, is it just you're doing more complex jobs and so they cost a lot more but they -- but you are doing fewer of them?

The big impact really comes in the Appalachians, where we saw a little bit of a resurgence in our traditional shallow vertical fracks in the fourth quarter. That's a phenomena we see every year. Sometimes -- some times really relates to people's budgets, year-end type work that they try and get completed. But interestingly enough the number of large horizontal fracks in the Marcellus actually went up by seven quarter-to-quarter. So it is really just a phenomena we see traditionally in that business. I don't think there was a great difference that we saw in our Texas markets over what we've seen in the past.

In the Permian market for -- are the jobs that you're doing right now on pressure pumping mostly vertical jobs, or are you also involved in some horizontal work in the Delaware Basin?

It is a little of both. I think you have to keep in mind that the horizontal drilling in the Permian is really only 15% or 20% of the wells that are currently being drilled. So traditionally you would probably say that's still a very much vertical market. But we do see that changing and I expect that those numbers will ramp up quite a bit over the next -- really, the next three quarters. So I think you will see more and more horizontal work in the Permian as we move forward.

In terms of the size of the crew for horizontal work in the Permian, what's the size of the crew and how many horsepower versus for the vertical jobs?

It really varies. The vertical jobs can be as little as 4,000 horsepower or 5,000 horsepower. The bigger crews on horizontals out there can be anywhere from 10,000 horsepower to 20,000 horsepower.

But there is a lot of deep -- The vertical wells, like you mentioned in the Midland Basin, they're fairly deep and relatively complex pressure pumping work and are you still using 4,000 horsepower there, or more than that?

There's such a broad range of wells being drilled out there. It is really hard to give you a number that's an average.

Okay.

If you want, we'll delve into that question later and try to get you back an answer at a later date.

That sounds good. Thank you, sir.

Your next question comes from the line of Kurt Hallead with RBC Capital. Please proceed.

Hey, good morning.

Good morning, Kurt.

I was curious, these new rigs that are coming into the marketplace this year and the vast majority of those are contracted, where -- what basins do you see those rigs going to?

Let me just give you a snapshot of them, Kurt. I am going to talk really probably about the 18 that are already contracted. I think this is indicative of what the rest of them are going to look like. About half of those are going into the Eagle Ford. There is four that are going into the Marcellus, four into the Rockies, and interesting a couple in West Texas. And I should point out this is the first time in our history we have had new rigs going into west Texas. Which, again, is -- partly for a long time we did not think that the west Texas markets would support new-build rigs and support three-year contracts, so I think this is a significant change in that particular market.

Okay. You reference that you have another 25 rigs that you could bring into the market, new rigs in 2012. So, 25 this year, 25 next year. Is 25 the max you can bring in, in any given year?

No, Kurt. Actually we think we can increase the production. If you think about it, that's basically two per month, and we think we can go to three or four a month. Frankly, the number that we are putting forward is a number that we think is comfortable for the market to absorb. I think it's been the case that the major players have been pretty disciplined in the growth of new rigs and we have been able to, as you know, and you your question, your prior question made reference to, secure contracts and commitments for virtually all the rigs that we're putting out this year. And that gives us some confidence in continuing the program.

What kind of spare capacity of existing rigs do you have that, say, can serve the need to the market? My understanding is that the bulk of interest is in the 1,000 horsepower to 1,500 horsepower type of range. So what do you have sitting on the shelf that you can readily bring in, in addition to those new rigs?

Kurt, I tried to answer that question a few minutes ago. We have virtually no 1,500s left in the fleet. There is approximately 30-1,000-horsepower rigs that we think are capable of going back to work, but I wouldn't just limit it to that. West Texas -- we do believe that there's certainly markets there that 750-horsepower and 900-horsepower rigs are going to go back to work. And I think we have an equal number to the number I told you for 1,000-horsepower that are capable of going back to work in west Texas.

Okay. And then on a cash margin basis -- you may have mentioned the second quarter earlier, I was not on for that section of the call. As you go forward there is increased labor costs, maybe some increase on material costs. What would your expectation be for cash margins as the year progresses? Do you think they can accelerate from where they are right now?

Kurt, we spoke to second quarter and really didn't speak beyond that. For second quarter we believe revenue per day in the US will go up $600 to $700 a day, and the margins will go up around $400 a day. Again, that's US. Canada more or less shuts down. We're going to average two rigs, and the overall margin for those rigs ends up being break even. So the effect of that, when you put the U.S and Canada piece together, is that you're looking at an average revenue per day increase of about $200 and a margin increase of about $250, taking the two businesses together. Looking beyond that, rig availability is tight, so one would expect prices would continue to improve, but we haven't made any statements with respect to that accelerating or how much that might be.

Okay. Great.

I don't know if you heard this, but one of the things that we said is that we expect improvements in utilization in margin in the second quarter in the US to overcome, in effect, $13 million of, in effect, margin from drilling in Canada that we lose sequentially in the second quarter due to the seasonal shutdown.

Okay. On the pressure pumping front. You know, you have 200,000 or so horsepower coming in, about looks like 100,000-something already booked. Clearly you feel confident about the other 100,000, so is it -- would it be reasonable to think that additional horsepower is going to be also targeted say for the Eagle Ford or the Marcellus, the Bakken, what -- how are you looking at the market opportunities right now?

Kurt, we'll put that equipment to work in whatever location we think is most attractive to us at the time. I want to add one additional thought, which is that we're open to term contracts in this business. We've got a lot of experience from our drilling business with term contracts. We like to be sure that when we do term contracts, that they're real take-or-pay contracts and that they're take-or-pay contracts at the kind of margins that we really want to receive for this business, recognizing the significant upward trends in the business. So we're quite open to it, and we're quite into discussions with a number of our customers about making this equipment available to them. And that's one of the things that we really are thinking about, so the equipment could go to a number of markets depending, frankly, on customers' demand and the attractiveness of the terms of the offer.

Okay. And if I may, just one follow-up on that one, Mark. Patterson historically has been a more known for being the spot market operator and not the term contract operator. When you look at your land rig fleet right now, what's your mix of spot versus term work?

I think half and half. Of the 200 rigs we have working today, I think we mentioned we would average 106 I believe term contracts for the rest of the year. So it is a much different picture, Kurt, than it ever used to be.

That's it. Great. Thank you.

Your next question comes from the line of Arun Jayaram with Credit Suisse.

Good morning, guys. I wanted to talk to you a little bit about -- a lot of good questions. How should we think about your rig count, and maybe an exit-year rig count? I think you're sitting with 199 rigs today, you've got about 19 incremental rigs through new builds, so that puts you just under call it 218, plus Canada coming back in the fourth quarter. How many re-activations do you have the ability to do on a quarterly basis going forward?

We're pretty optimistic about the market. The numbers you put forward I think are very, very reasonable that we have, as you point out, this program of 25 new rigs for 2011, and we put out in effect through the end of April six of those. So that gives you 19 additional rigs and a 200-rig count approximate number, so that brings you to 220. Quite frankly, we're optimistic about the second half of the year and our ability to put incremental rigs out, particularly into these liquids rich and oily basins. I think that's a real opportunity for our Company. Doug gave you the numbers about the 1,000-horsepower and 900-horsepower and 750-hoursepower rigs that we have. We're thinking, and we try to say so in the prepared remarks, that we're optimistic about putting incremental rigs into Mid-Continent and the Bakken. So overall a number north of 220 for US count is something that we would be pretty comfortable, and then you factor on top of that how bullish you want to be about Canada. Obviously last year was the best year in several years for Canadian drilling. We're pretty optimistic that this year could be in the same kind of way. So you take that 220-plus number, north of 220 number, plus the Canada and you get a pretty good number.

Right.

You want to put in an exit of 15 in Canada, you can put in whatever numbers you want to think. You guys are the experts on the long-term numbers.

I don't know about expert. I guess my question, Mark, just thinking about, in a quarterly basis, I assume you are working pretty hard to get the 25 new builds out on time and things like that, but how much availability do you have to do re-activations? Is it ten rigs a quarter, is it eight? I'm trying to understand what you can do from a capacity standpoint?

I think we've got tremendous capacity. The interesting thing about our Company is really that we've, as you probably know, we've got large yards in many of our geographical areas with substantial capability of putting out rigs. We have a lot of rigs that are pretty ready to come to work. So I think that the constraint for us is not our ability to get them out, so to speak. It's really just the customers demands and the terms we want to work on. Those are for us the ones that are the most concerning. And the ability to staff them with the kinds of people and the kinds -- and provide the kind of service to our customers that is our standard.

Right.

I would add, back in 2008, you might recall, that we averaged about putting out about ten rigs a month when the demand was there. I think we still have those kinds of capabilities. As Mark indicated, what goes out is based on our customer's demand and we'll try to be very responsive to that.

My next question, John, or Doug, would be just on the west Texas market. I think you're running 45 rigs in west Texas. I think your rig count has played a lot of catch up. I think you weren't early out of the gate because others were putting rigs out at much lower margins. But can you give us a sense of tendering activity and just how much operating leverage you have in that marketplace? Can you be at 70 rigs by year-end? I am trying to understand that west Texas market, because it's pretty key for you.

I am not going to throw out a number. I think 70 would certainly be on the high side. If the demand is there and we can get the pricing that we're looking for, we certainly have the capability of -- we have enough rigs to be able to do that. I guess I would be a little surprised if the number got that high, but it really does depend on how much take-up we see I think in the horizontal drilling parts out there. And, again, I really can't give you a number, but we do anticipate that, that's one of the markets that we know we have got some capacity and are working very hard to try and improve our pricing and get some additional rigs back to work.

Okay. And my final question. Doug, you mentioned about the potential, or your expectations, to get some margin growth on the pressure pumping side, and Mark in his comments talked about pricing power. Can you help us think about what the sequential margins could do in Q2? Or, were your margins in Q1 impacted by weather, and what kind of sequential improvement in margins could we see with the pricing power, et cetera?

I think we did lose some jobs in the first quarter due to weather and margins would have been a little bit higher had we not lost that, because when you lose the work you still do have to pay people. If I took a look in the second quarter, I would guess that we might see as we calculate the margin there going from about 34% to somewhere 36%, or so.

That's fair. Historically, obviously it's a different fleet, but you've generated margins a little north of 40% in some of the peak years and universal. Based on your expectation as this market develops you're getting into some higher-end jobs, can we revert to that type of level by Q4 if things play out as expected?

I don't want to be specific about Q4, but I do believe, yes, we can still generate those type margins. And the real key is the business has changed from our traditional Appalachian work. You are doing very, very big jobs, and if the timing moves or weather delays you, it hurts your margins. Certainly the pricing has been strong and I don't see any reason we can't get to those numbers. I wouldn't speak to whether that's third quarter, fourth quarter, this year, next year. It is just really a matter of if you can schedule it well, the pricing is strong and those margins I think we can still achieve at times.

Okay. Thank you very much. That was very helpful.

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

Thanks. Good morning. Just a couple of follow-ups. First, on the re-activations, can you remind us, are you going to require a term contract to bring something out of stack or refurbish it? Or, is the market getting strong enough you're willing to reactivate and put it in well-to-well jobs in the spot market?

Jud, I think it is a little both. We're certainly not demanding term contracts. Obviously, that's a starting place. But I think the other end of the spectrum, we're not likely to bring a rig out of stacked, that's been stacked for some time, just to drill one ten-day well. So we're looking for a number of wells, or something we see where we can string some things together. And it obviously will depend on how long the rig has been down. But I think it is a little both. If we can get a term contract, certainly we're pushing in that direction. But I think primarily in the places where we have a lot of capacity today, certainly the west Texas marketplace, and it is the one market that probably has the lowest percentage of term contracts.

Okay. Thank you for that. Next question. On thinking about margin per rig-day and progression in the back half of the year, you will obviously be putting out APEX rigs which will be a very high margin and you presumably will be reactivating some of the conventional rigs at lower margins. Do we still would we still see, probably on average or margin per rig-day gravitate higher when we kind of add all of that up, given that you will have some two different extremes in terms of margin per rig-day and the types of rigs that will be going into your active fleet?

If the new rigs and the conventional rigs are similar numbers, I would think that we would still see our margins move up toward. But, as Doug mentioned, we've got a lot of our conventional fleet that's not active at this time, it's somewhere towards 140 rigs that fall in that category. If things got extremely active and you activated 100 rigs over a couple of quarters, that could bring the average margin down but bring the profitability up significantly. I think it is a matter of mix.

Yes. That answers my question. That's exactly what I was looking for. Congratulations on a good quarter. Thanks very much.

Thank you.

Your next question comes from the line of Dave Wilson with Howard Weil. Please proceed.

Good morning, gentlemen. Kind of doing some follow-ups here. Doug, in the past and this morning you made mention of having capacity to add west Texas and the Rockies, whether it be new rigs or re-activations. In the beginning of the year -- from the beginning of the year, it looks like you have added a handful of rigs to these regions. Going forward, what do you see as a catalyst to get these operators to move forward? Besides -- we've seen high oil prices for a while now, but are there any overt catalysts you are looking for, or have developed over the last quarter, that you're seeing, that you feel more confident that you're going to be able to put rigs back to work in those regions?

Some of it, Dave, is because of the scarcity of really good quality 1,500-horsepower rigs, some of the situation is we're currently doing some minor refurb on some rigs we know will go out in the next couple quarters. I do think that the activity and the bid activity in places like west Texas continues to increase. We've had situations where people have held back their program slightly because of fires in west Texas and some other things. So we see incremental demand coming over the summer months, and we expect, knowing what we know about our customers, in a lot of these markets like the Bakken and West Texas, I think people are really just still putting their programs together and are going to get going later in the year.

Great. Thanks for that. Another follow-up. I know we have danced around it, but with regard to day rates going forward for new builds, do you think there is opportunities to push day rates further from current levels outside of for fuel and those kind of costs and seems like there is just healthy supply-demand situation at current rates. Given where commodity prices are, do you get a sense the demand for the new builds is somewhat elastic regarding day rates, that there might be a possibility to push those higher?

Absolutely. I think they have pushes higher over the last six months and I think they will continue to push higher.

Okay. Great. That's it for me.

You have no further questions at this time.

I would like to thank everybody for joining us on this call. We look forward to speaking with you again at the end of our second quarter and thanks, everybody, for their participation.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.