Patterson-UTI Energy Inc (PTEN) 2012 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2012 Patterson-UTI Energy, Inc. earnings conference call. My name is Fab and I'll be your Operator for today. At this time all participants are in listen-only mode. Later we will conduct a question and answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to Mr. Mike Drickamer, Director of Investor Relations. Please proceed.

Thank you, Fab. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the 3 and 12 months ended March 31, 2012. Participating on today's call will be Mark Siegel, Chairman; Doug wall, President and Chief Executive Officer; John Vollmer, Chief Financial Officer.

Again just a quick reminder that statements made in this conference call, which state the Company's or management's intentions, beliefs, expectations or predictions for the future are forward-looking statements. It's important to note that actual results could differ materially from those discussed in such forward-looking statements. Important factors that could cause actual results to differ materially include, but are not limited to, deterioration of global economic conditions; declines in customer spending and in oil and natural gas prices that could adversely affect 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 labor, equipment, supplies and materials; supplier issues; weather; loss of key customers; liabilities from operations; 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'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. And the required reconciliations to GAAP financial measures are included on our 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, Mike. Good morning and welcome to Patterson-UTI's conference call for first quarter 2012. We are pleased that you were able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended March 31. And then I will turn the call over to Doug Wall, who will share some detailed comments on each segment's operational highlights for the quarter, as well as our outlook. After Doug's comments, I will share some closing remarks before turning the call over for questions.

Before I start, I'd like to take a moment to welcome Andy Hendricks to our team. Andy recently joined the Company as our Chief Operating Officer and we are delighted to have him. We believe Andy's experience and leadership abilities will help us to continue to execute on our goal of delivering exceptional shareholder value.

Turning now to the first quarter, as set forth in our earnings press release issued this morning, we reported net income of $97.3 million, or $0.62 per share, for the first quarter ended March 31, 2012. EBITDA for the quarter improved to $281 million, marking the 11th consecutive quarter of EBITDA growth. There were many challenges during the first quarter. As you are all aware, the weak pricing environment for natural gas led many of our customers to reallocate their capital spending plans towards oil and liquids-rich basis. On the contract drilling side, we have moved people and equipment out of natural gas basins to better align ourselves with our customers' drilling plans.

In the pressure pumping business, the slowdown in natural gas activity, some seasonal weakness in the Northeast, and the overall excess supply of frac equipment have combined to create a difficult pressure pumping market in the terms of both utilization and pricing. Despite these challenges, our first-quarter results are actually slightly better than the expectations we had in the beginning of February 2012.

In terms of revenue, we saw sequential growth at both of our core businesses. But the majority of the growth came from our contract drilling. In which day rates continued to improve and activities levels benefited from five new APEX rigs that were added to the fleet. In pressure pumping, despite the challenges in this market, we were able to achieve a slight sequential increase in revenues as our growth in our Southwest market offset the decline in the Northeast. In the current natural gas pricing environment, our customers in the Northeast seemed to be delaying well completions, which accentuated the problems arising from the oversupply of equipment in this market. The lower utilization, combined with some pricing erosion in the Northeast, negatively impacted our margins. But because of the strength in the Southwest, our overall gross margin percentage only fell by approximately 80 basis points, outperforming our internal expectations.

Earlier this week, we announced that we successfully completed the sale of our flowback business, ERS, for $42.5 million in cash and retained its associated financial working capital of approximately $5 million. This non-core operation accounted for approximately 3% of total pressure pumping segment revenues.

I would now like to turn the call over to Doug.

Thanks, Mark. I'm going to start this morning with some commentary on the drilling company and then finish up with some comments on our pressure pumping business. So starting with contract drilling. For the quarter, revenues within our contract drilling segment increased by 4% sequentially, to $489 million. Operating days were up by 1%, and average revenue per day was up by 3%. Our activity levels remained strong during the first quarter, with an overall sequential increase of 5 rigs to 237 rigs. In the US, while industry rig counts trended lower during the quarter, our average rig count actually increased by 4 rigs to 224. And in Canada our average rig count increased by 1 rig to 13. In the US, the increasing rig count was facilitated by our broad geographic footprint which allowed us to move 11 rigs during the quarter out of dry gas markets, and into the oily and liquids markets such as the Eagle Ford, Permian, and the Bakken. All of these rig shifts were paid for by our customers. In addition, in many cases we were able to earn higher day rates in the new markets. Although we lost some operating days associated with these moves between markets and customers, we feel the rigs are now in better markets given the current commodity prices.

For the quarter, average revenue per operating day increased by $670, to $22,650. This was driven primarily by growth in the US of $650 per day. Average operating cost per day increased by $380 to $13,080. Both average revenue per day and average cost per day increased more than expected. Largely due to incremental mobilization revenues and costs related to the movement of these rigs between regions.

Demand for our APEX rigs continues to be strong. Our existing fleet of APEX and other preferred electric rigs continued to work at near full utilization levels. Additionally, we believe that our fleet of highly capable mechanical rigs are ideally suited for the markets in which they are working. With almost three-quarters of our active mechanical rigs drilling in either the Permian or the Midcontinent. Looking forward, we expect the rebalancing of the rig market to continue with additional rigs moving from dry gas to oil and liquids markets. With the movement of the rigs in the first quarter, we now estimate that approximately 68% of our rigs are drilling wells for oil or liquids-rich targets. This increased focus on oil and liquids markets, combined with our term contract coverage, has lowered our exposure to natural gas rigs in the spot market from almost 30 rigs last quarter to approximately 15 rigs currently.

Our total term contract backlog is now estimated at $1.7 billion. Based on contracts currently in place, we expect to average 153 rigs under term contract in the second quarter and 132 during the last three quarters of the year. Historically, we have reported our term contract coverage based on rigs with an initial contract duration of at least 12 months. Consistent with an industry shift to classifying term contracts as those with an initial duration of at least six months, we are now reporting our term contract information in this same manner.

In terms of our newbuild program, we completed five new APEX rigs during the quarter. While newbuild conversations with customers have slowed, we signed two additional term contracts for APEX rigs during the quarter. Operators do seem to be waiting to see if high spec rigs are released from gas basins and become available in the spot market without a long-term commitment. We believe this impact is dampening the near-term demand for newbuilds. Accordingly, while our previous plans called for us to increase the rate at which we completed rigs in the back half of the year, we have decided to maintain our current pace, effectively deferring 6 of the 30 rigs previously expected to be built in 2012 now moving them into 2013. We now expect to complete 24 new APEX rigs this year, of which 15 are already under contract.

Due to the impact of the annual breakup in Canada, our forecasted revenues in the drilling segment are expected to decline sequentially. We expect our second-quarter rig count to average 226 rigs, including 225 in the US and 1 in Canada. Although additional new APEX rigs will be completed in the second quarter, our expectation is that our US rig count in the second quarter will remain essentially flat, due to the loss of rig days as rigs transition between both customers and markets. Average revenue per day is expected to be flat in the US, but down about $400 overall owing to the Canadian breakup. Looking at our expectations for margins, in total, we expect our average rig margin per day during the second quarter to be flat with the first quarter levels. This reflects a more than $100 per day improvement in the US, but offset by a decline in Canadian rig activity and margins associated with the seasonal breakup.

Turning now to pressure pumping. Revenues in this segment came in pretty much as expected, up slightly from the fourth quarter at $242 million. As Mark mentioned earlier, our gross margins compressed slightly, reducing EBITDA from this segment by 2% to $70.6 million. However, the two regions we compete in tell a vastly different story. The Southwest market remains very strong during the quarter, as revenue growth approached 12%. The strongest markets continue to be in South Texas and the Permian. As activity levels improved, so did pricing. And we were very pleased with the margin improvements we achieved. Labor costs and costs of products continued to be a challenge. But we were pleased with our ability to manage these accordingly which led to our improvement in margins. Unfortunately, we are now seeing an influx of equipment and new competitors in these two markets. And have already seen a much more competitive marketplace with the resultant pressure on pricing.

As one of the larger competitors in the Permian, we do feel we have some competitive advantages in terms of infrastructure and people. However, it certainly has become more difficult. The Eagle Ford market has been inundated with frac equipment floating out of the Haynesville, and we believe this market is saturated with crews for the time being.

Turning to the Northeast market, we saw an acceleration of the activity decline. As operators responded to the worst gas pricing environment in the last 10 years. Revenues in this market declined by 14% sequentially. We believe many operators delayed completion work during the first quarter, due in part to the weakness in natural gas prices, as well as the increased cost of completing wells during the winter. Spot market pricing in the Northeast has become extremely competitive, and we estimate it has declined around 20%. We do expect to see frac crews leave this market for oilier pastures, over the course of the next few quarters. But expect this market to remain depressed until gas prices recover or the Utica activity ramps up.

We have sent some crews from the Northeast to work in Texas, thereby helping with the tight labor markets in Texas. And helping to alleviate some of the operational inefficiencies caused by lower utilization in the Northeast. We continue to believe in the long-term prospects of the Marcellus, but we will certainly consider moving our equipment and people to other markets where we can maximize utilization and generate the highest returns. Logistics continue to be one of the biggest challenges across the pressure pumping industry. A shift of people and equipment is not just as easy as driving the equipment to a new market. Logistics, infrastructure, and one's supply chain are key elements in being successful in any market. And this rapid shift from natural gas basins to the oilier basins has created a huge logistical challenge for the industry. Given our exposure to only two regions, our established infrastructure has allowed us to avoid some of the logistical issues faced by many of our competitors.

During the first quarter we took delivery of 30,000-horsepower, ending the quarter at approximately 660,000 total horsepower in our fleet. Most of this new horsepower was delivered late in the quarter, primarily to the Permian. And consequently, it did not contribute to the quarter's earnings. I should point out that in general, we have not placed any orders for pumping equipment since last summer. At this point, we have decided that we will not deploy any further new pumping equipment to the market until demand improves.

Let me finish up this morning with our expectations for the second quarter in pressure pumping. The challenges in this business that I outlined earlier will certainly have an impact on our activity level and earnings in the second quarter. Based on what our customers are currently telling us about their plans for the quarter, we expect our revenues in this business to fall by approximately 20%. And gross margins to fall to approximately 27%. Please keep in mind that part of this 20% revenue decline relates to the sale of our ERS flowback business, which contributed some $7.4 million in revenue during the first quarter. We do believe the pressure pumping industry will be challenged in the next two or three quarters, as reduced demand in dry gas basins, the influx of new equipment and competitors, and logistical challenges will continue. However, we do expect we will see some improvement in our activity level during the latter half of the year.

But before I turn the call over to Mark, just a couple other quick financial comments. In the first quarter, SG&A was lower due to some one-time items. Looking forward, we currently expect SG&A to be approximately $17 million in the second quarter. We expect full-year 2012 depreciation of $516 million including $127 million in the second quarter.

So with that I'll now turn the call back to Mark for some concluding remarks.

Thanks, Doug. As mentioned the first quarter had its challenges. But we were able to effectively manage these challenges. And I am very pleased with the results we were able to deliver in the first quarter. Our long-term outlook for our industry remains positive, and especially for our two core businesses, which are keys to unlocking unconventional oil and gas. Despite the continued rebalancing of the rig market, we continue to see strength in our US rig business. In the near term, we may see some loss daily rig utilization as rigs move. Importantly, our broad geographic footprint has allowed us to easily move rigs between regions in order to align our rig fleet with our customers' changing spending plans.

On the pressure pumping side, the market is currently dealing with excess equipment caused by the increase in additional new equipment and the decrease in activity in natural gas markets. As noted in our press release, we are doing our part to solve for these issues. Our last order for new equipment was made in third quarter 2011. And we plan not to deploy the additional 110,000 horsepower of pressure pumping equipment on order until demand improves.

It's important to note that we are not a new entrant in the pressure pumping business. We've been in this business for more than 30 years. We have a proven track record of managing this business through commodity cycles. Moreover, we have adapted to changes in the industry by having a relatively young fleet of high horsepower equipment with more than two-thirds of our fracturing horsepower less than five years old. Despite the uncertainties in this business, and the impact these uncertainties have had on our stock price, we believe the pressure pumping business has substantial long-term value.

As Doug mentioned, we are planning to defer some of our new APEX rig deliveries into 2013. With these and some other changes, we expect that CapEx for 2012 will be reduced from approximately $1.1 billion to $1 billion. We will continue to be prudent in deploying capital. As a whole, we believe Patterson-UTI is very well-positioned. We have excellent equipment and highly trained experienced people in both of our core businesses. We have a proven track record of being operationally nimble enough to manage the challenges we face. And we are financially strong enough to benefit from whatever opportunities the market may present.

So in conclusion, as we think about the service industry, it reminds me of Einstein's comment that life is like riding a bicycle. You have to keep moving to keep your balance. We keep moving and adapting in a rapidly changing oil services market. In closing, this morning I am pleased to announce today that the Company declared a quarterly cash dividend on its common stock of $0.05 per share, to be paid on June 29, 2012, to holders of record as of June 15, 2012. Lastly, we want to thank our customers, employees and shareholders for their continued support for our Company. Our strength is derived from all of you.

Operator, I'd now like to turn the call over to questions.

(Operator Instructions) Robin Shoemaker, Citi.

Good rundown on everything that's going on. I wanted to ask about, if you could describe your contractual situation with customers in pressure pumping and how that is affecting your forecast in relation to your 20% revenue down forecast for the second quarter.

Yes, Robin, this is Doug. We didn't mention it this time but we have about 155,000-horsepower committed under what we call term contracts in the pressure pumping business. Those contracts are proceeding. We certainly had some conversations with those customers, but those customers are proceeding with their work. I think the bigger issue really has been the spot market pricing. And I think one of the biggest things we've seen is some very customer-specific shutdowns that are expected in Q2. And they are in markets such as the South Texas and West Texas that are really impacting our numbers. But those are typically what we would call spot market crews. Even though we've been working for those customers for quite some period of time, they're not on take-or-pay contracts.

Okay. And what's driving your decision now in terms of, if a fleet is insufficiently utilized or is facing a very low pricing environment, how would you decide to keep working that fleet of pressure pumping equipment? Or idle it and reduce your costs associated with that?

The two markets are very different. What we've mentioned to you, Robin is that of some new 110,000-horsepower that is still to be delivered to us this year, we have chosen not to even introduce that equipment into the marketplace. With our existing equipment, we are almost every week looking at the utilization of that equipment, deciding whether we could turn five crews into four. We're looking at all sorts of situations where we're trying to reduce the number of crews and people to try and meet the demand that we see in the marketplace. But also giving us the flexibility to quickly turn that around if we see demand increase in a different region or a different market. So obviously it's economics. We don't really want to have six crews in the Marcellus operating at 30% utilization. If we can do that, if we can accomplish the utilization or the activity with four crews, and reduce the cost, then that's what we will do.

Okay. Thanks very much, Doug.

Scott Gruber, Bernstein.

Regarding the deferment of new pumps into the market, I'm curious, why not introduce the new pumps and swap out some of the legacy equipment? I assume the expected maintenance downtime on the new pumps is superior to the legacy equipment.

Scott, we have a fleet of very new equipment. More than 70% of our equipment is less than five years old, so we have very little what I would call legacy equipment in this marketplace. So the equipment we do have in the field is as new high-tech, high-spec as you can get. Certainly, there's a couple scenarios where we will flush out some crews to have them all of the same type and size of pump. But it just doesn't make any sense at this point. We would like to keep these, the new equipment as intact crews. And as the market improves, we do think there will be some opportunities to put them together as a complete crew later in the year.

Okay. And then you highlighted Marcellus pumping pricing in the spot market down about 20%. How do your contracts roll in the Marcellus? Are most of those going to reprice before the end of the year?

Scott, I'm talking from memory here. I think one of those contracts actually does reprice by the end of the year. The other one does not.

So one more to reprice in '13?

In fact, I just got an update on that. One of them is actually mid-2013. The other is actually late 2013. So pricing will remain intact. The next pricing indication we'll see there on that crew is mid 2013. With the second one late in 2013.

Okay. Good coverage there. And then turning to the Permian, are you still receiving inquiries for additional vertical drilling in the basin? Or are the incremental inquiries dominated by horizontal work?

I think it's both, Scott. Certainly that market, as you know, has been slow to move to horizontal drilling. So I expect that over the next couple of years, we're going to see more and more horizontal drilling which certainly will have higher horsepower requirements for the frac crews than a typical vertical well. But today we're still seeing demand in both sides of that equation.

So absent a big move in crude, you'd expect growth in the conventional vertical drilling as well?

Yes. I think you will continue to see growth in both.

Okay. Great. I'll turn it back.

Joe Hill, Tudor, Pickering.

Doug, you referenced some big customer shutdowns for Universal in the second quarter in South Texas and West Texas. Do you view those as anomalous or indicative of a market trend?

Joe, at this point I really can't answer that. We try and stay in very close contact with our customers. I think there is different issues in both of those shutdowns. And when I say shutdowns, one of the customers told us they're going to shut down for a couple months. I really don't know the logic or the reason behind it. But they have been fairly consistent in telling us that -- be ready on such and such a date because we plan on getting back to work.

Okay. And of the 20% hit to revenue, I believe that was quarter-on-quarter, how much of that is going to be pricing versus utilization, driven by things like the shutdown?

Joe, I'm not sure we can really answer that. Obviously, it's a mix. Our projections are really based on what the local guys are telling us. Obviously some of it's pricing, some of it's activity. I would say, just as a general rule, probably the bigger impact with pricing is in the Marcellus. The bigger impact in Southwest is likely activity.

Got you. Okay. And then do you guys amortize mobilization over the contract or do you take it lump sum?

Are you talking rigs or pressure pumping?

Yes, sir. Rigs.

That would be lump sum.

Lump sum? Okay. Can you estimate how many days you lost to mobilization above the norm in the first quarter?

We don't have that here available.

Okay. And then last question, you guys ought to be cash flowing something around $1 billion this year. Or close to it. Obviously it's a moving target. Given that you're exercising some discipline in your capital budgeting, what are the prospects for using some of that cash flow for share repurchase in the near term?

I think I've given this answer on multiple occasions but I'll give it again. Which is that at every one of our board meetings, our board considers carefully the question of dividend and buyback and other possibilities for our Company. As the stock price has declined to these low levels, obviously, the buyback has become something even more attractive, from our perspective. We have an existing authorization to buy back stock and we are considering it.

Okay. Thanks for the color, guys.

Marshall Adkins, Raymond James.

I hate to keep dwelling on the pressure pumping, but might as well. Good guidance, helpful guidance on the 27% margins, I believe it was. But any sense of when we think those margins in pressure pumping bottom out?

Marshall, that's a tough question to answer. It's a good question. I wish we knew the answer. I think you're seeing this continuous shift of equipment and crews from natural gas markets to oily markets. As I alluded to in my comments, it's a little bit more difficult in the pressure pumping business than obviously the drilling business. The rigs really don't know whether they're drilling in oil or gas. Pressure pumping equipment you just have to have so much infrastructure and get your supply chain and all those things worked out. I do think we are starting to see some added pressure on pricing, even in the oily markets. And what's going to be interesting, I think, is just to see how much equipment either gets idled, deferred. I think we'll see continued pressure on pricing until such time as supply and demand balances out more. And I do think -- that's why I said earlier I think we're probably in for another quarter or two of some choppiness in this market.

Marshall, the thing I'd want to add to what Doug said is something which I suspect you and everybody else on the call probably is well aware of. But as we and others make the decision to defer deliveries, to idle equipment, as it's delivered, et cetera, that's going to change, as I see it, what's been the increased supply and now oversupply of equipment. And then I suspect as demand continues to increase, we'll see a meeting of the two. And that's what I think's going to happen. How quickly that happens is a pretty hard thing for any company to predict, since we only see our own data. But I think that's the thing that we think is happening, that there is more disciplined being shown. Also, we also note that for a long time, private equity money was coming into this part of the industry. And driving some of the newbuild activity. We think that's obviously slowed or stopped.

All right. That's good color. How much of your equipment is parked on the fence today? I know the next 110,000 you're going to part on the fence, but any sense of how much is already parked on the fence?

Our own or the industry?

You're own. Yours.

All of equipment worked in Q1, Marshall. It just, particularly in the Marcellus, probably on any particular day, we may have three or four out of the five or six crews that are actively working. So it's a little bit of a jigsaw puzzle with all of the various regions that we operate in up there. And there is some efficiencies. Obviously, those frac crews are selectively placed close to the markets where the work is. And yes, you could consolidate, but what it means is that you're driving equipment much greater distances, so you're adding cost by doing a different model than what we're doing today. But I'd say there's no question that, particularly in places like the Marcellus, there's a lot of equipment every day sitting around idle, but it may be working later that same week. It's just far more spotty than it ever used to be.

Sure. Last question for me. You have roughly, it looks like two-thirds of your rigs under what we call longer-term contracts. Do we think that percentage is going to go up or down over the next year? And what's your current outlook for the nine that aren't contracted? Are you getting decent inquiries? The ones that are going to be delivered.

Let me handle the second part first. Even though I said discussions have slowed, we're still having conversations with people. But I think the real key there is there are a lot of customers there that are somewhat unwilling to sign a three-year term commitment. They certainly want the rigs or they want the style of rig. I think a lot of them believe today that they can still get a similar type rig that gets turned loose from one of the natural gas markets. So that's why we think today we've seen some reduced demand for newbuilds. I do expect by the end of the year we will see increased demand for newbuilds. And we're certainly having a lot of conversations with customers that are already talking to us about 2013 requirements. So do we believe that we're going to contract the other nine? I think the answer is yes. The first part of your question was really, where do we think long-term contracts will be a year from now?

Yes. It sounds like what you're saying is that the percent under contract maybe dips a little bit here short-term, but by the end of the year is firming up, is what I was getting to. Does that sound --?

I think that's probably true.

Marshall, I think maybe putting it slightly differently is I think I'd say we think demand for newbuilds remains strong. The demand for contracts has perhaps slowed.

Okay. All right. Thank you all very much. Appreciate it.

Waqar Syed, Goldman Sachs.

Just a question, shifting to the drilling side, and on the day rate environment. Are you seeing any pressure on any class of land rigs in the oily basins right now?

To this point we really have not. In fact, in some cases, pricing is still moving up albeit at a very slower pace.

Okay. And what's your prognosis for maybe three to six months time for some of the mechanical rigs or 1,000 or 1,500 horsepower mechanical rigs that are in the system? Do you see any pressure on those rigs?

I'd have to say at this point, we don't expect any meaningful pressure. Virtually every high-spec quality rig today is working or utilized. And three quarters of our rigs that you're talking about here are either in the Permian or the Midcontinent, which are very strong markets. I don't see them being further replaced by rigs coming from other regions.

Okay. Bigger picture, I understand you're pushing some of the newbuild to the later years. And right now maybe the demand is a little bit softer. But why not continue to build? Because if you believe in the high grading that's happening in the industry, why not continue to build rigs for that at the current pace?

We are. Effectively for the last several years, we've been building them at approximately a 25 rig per year basis. What we had elected to do was accelerate that in the second half of the year to a 30 rig delivery schedule. And then what we basically decided is it seems prudent in this market environment to stay at the 25 rate. And we've come to 24 as the logical number for this year in light of where we are currently. So we really see it as staying at the same basic rate we've been at for the last several years. And just effectively deciding to postpone the acceleration that we had otherwise planned.

Sure. And then on the Canadian market, what's your view beyond the breakup, what are your customers saying regarding the second half this year in terms of activity levels?

Waqar, I think it's going to be very similar to past years. There is certainly some nervous in the Canadian market, I think primarily with gas pricing. But interesting enough, I think Canada is seeing the same shift to, a big chunk of the rigs in Canada are now drilling for either oil or certainly in the oilier markets. And so I expect a very typical response after breakup in the Canadian market. I don't think it will be higher. I don't think it will be substantially lower. It just seems to be pretty solid, really. It will ramp up a little bit in Q3 and then we expect that by Q4 we will be back very similar to what happened last year.

Okay. And then just one final question. On the Permian, longer-term, what's your view on how many rigs could be working incrementally in the Permian area? And in terms of your feel for the split between vertical drilling and horizontal drilling?

We've seen some numbers and some other people have quoted there could be another 100 to 150 rigs go to work in the Permian. If you go back and look at the previous peak, those numbers wouldn't surprise me at all. We're still not anywhere near where we were I think in 2007 and '08, so I think it's highly possible. I think the shift towards more horizontal certainly is going to continue. And I think over time, we'll see far more rigs out there that are capable of drilling the horizontal wells, which obviously has some implications for the frac business, as well, in that market.

Great. Thank you very much. Very helpful.

Dave Wilson, Howard Weil.

Quick follow-on question. Doug, you mentioned customers waiting for the high spec availability to roll off into the spot market or roll into the spot market rather than going for newbuilds with larger commitments. Does this portend that day rates could be pressured? I know you said you just said that we haven't seen any evidence yet. But how should we interpret this from a dayrate standpoint? Are there going to just be that many more rigs in the spot market?

Dave, I really haven't seen any reason at this point to think that the high spec rigs have seen any pressure on pricing. And I think, because I create the floor or the ceiling, if you will, I think that that will remain. Those dayrate prices in those markets will remain similar to what they are today. I think if you think about the movement of rigs, particularly the high-spec rigs, the Haynesville has certainly borne the brunt of that. Today we're down to 10 active rigs in the Haynesville. I think the industry has 60 or 70. I think the bulk of the shifting out of the Haynesville has likely already happened. I think there's a question about the Marcellus and will rigs move out of the Marcellus. The real question there is the mobilization costs and can people really move those rigs back to some other market in an economic fashion. So I don't think you're going to see any huge pressure on dayrates. And it's really going to be driven by the fact that there is still a very high demand for the 1,500-horsepower high-spec rigs.

Great. Thanks for that. And then just a quick follow-on. Understanding this transition from natural gas basins to more oily basins, have you seen any instances where rigs have just been laid down in a natural gas basin and not relocated?

I'd have to say we've seen a little bit of that in the Marcellus. But I think in most of the other markets, both us and our competitors are still looking at replacing rigs in markets where they think there's better opportunities.

Okay. Great. Thanks for that color. That's it for me.

John Daniel, Simmons & Company.

Just two questions for me. The first one is, with much of the new frac equipment being idled, how do you see your R&M expense evolving over the next few quarters? For instance, will you guys, if a working pump breaks down, would you simply opt to park it in deferred maintenance and swap it out with a new pump? Or is there a way you can cut costs that way? Is that the plan?

John, it's an interesting question. We'll just have to see how that plays out. Typically for a pump to totally break down, is a pretty major expenditure. Given the relative newness of our fleet -- knock on wood -- we expect that not to happen that much in our case. But certainly just like the drilling business, we will look at each one of those decisions on a one-off basis and see what we think is more appropriate. Do you go spend the money on fixing the old one or do you replace it with the new one? But I think in most cases, we would probably err on the side of just going ahead with the repair.

Okay. All right. And then I want to come back to the rig pricing for a second. If we could go back and think about the evolution of, say, pressure pumping, we first started hearing about the pricing concessions last August. But that was limited to the gas market. Then in January it became pretty clear that the pricing pressures were beginning to emerge in some of the liquids-rich markets. And I just wonder if you see a similar pattern on holding with drilling because it seems like we're hearing about some pressures from some of your peers with rig rate declines in the gas regions, but the oil market is holding up. Do you think a similar pattern plays out here over the next six months?

I think pricing on the drilling side has actually held up remarkably better than pressure pumping. And again, John, I believe it's because really it's a supply and demand thing. The high spec 1,500, 1,000 horsepower rigs are still in relatively short supply. And I do think the prices on that kind of equipment will maintain themselves. And I think because of that, it is different than the pressure pumping business, where it really is hard to differentiate your equipment from somebody else's.

Okay. Fair enough. Just last one for me. With the frac equipment being idled, is there a specific metric you're on point as to when it gets reintroduced? Or is this really more of a gut feel based off customer conversations and bound inquiries? What would make you want to redeploy it?

It's probably the latter. Certainly a lot of it is gut feel but a lot of it is trying to -- this market has been so dynamic and customers changing their minds so quickly that we've really had to look at things. It's hard to look at past financial data and say -- I'm going to make my decision based on that. You pretty much have to go on what the customer and your gut is telling you about where it's going to be for the next couple quarters.

Fair enough. Okay. Thanks.

Brian Uhlmer, Global Hunter.

I have a couple quick questions. When we're talking about land rigs and deferral of the six rigs, is that semantics or is there anything, that they can be canceled? Or is there any type of penalty or payment that's already been made on those rigs?

Brian, when we order a rig, virtually half the cost of the rig is committed. We buy pumps and engines and drawworks and have masts and subs built by various suppliers. Once we commit to that rig, roughly 50% of the cost of that rig is committed. Now, having said that, depending on where they are in their construction schedules, you can defer some of those costs, you can ask them to slow down, we're not in such a big hurry. Once we gather up all those components, we start spending the other roughly $10 million capital cost of a rig. So, depending on where you are when you decide to make that decision either to defer or slow it down, you'll have varying degrees of being able to save the latter part of that $10 million. Now, we have not talked about canceling anything. At this point what we're talking about is deferring some of this year's rigs really into next year.

One thing I would just add to what Doug just said is there's no penalties involved for us. We have the components, and we simply elect not to assemble them at this point in the rig. And in effect, save that CapEx cost. But we're not in effect losing some money that we've already spent.

Right. And same question for the pressure pumping, that 100,000-horsepower. Is that going to get assembled, wheels up and everything, put together? Or is it going to stay in component form until you make the decision to do final assembly?

We don't typically do the final assembly ourselves. We do buy pretty much finalized equipment. In some cases, because there's different suppliers to put together a frac crew, you may buy your blenders separately from where you buy your pumps and your engines. We can defer some things there. But basically, the trailer-mounted pumps, if you will, you're pretty much committed to spending the amount of money to put the pump in the engine and the truck converter altogether on the trailer.

Makes sense. Quick question on cash taxes. What's your estimate for your percent of statutory tax that's going to end up as a cash tax in 2012?

Current guess would be about 5% of the total rate.

5% of the total rate will be cash taxes?

Yes.

Okay. Now, as I look out through Statement of Cash Flows, your CapEx guidance for '12 and assumptions for newbuilds for '13, would you be drawing on your revolver for your CapEx this year? Someone mentioned a lot of free cash flow this year and I'm not getting that number. I'm just trying to rectify those two numbers. Aren't those pretty even to potentially cash negative throughout 2012, in your view?

Going into the year, our expectation was that we would borrow on our line some. The big factor, I think, is going to be how much investment is there in working capital, which obviously is driven by volumes as you get toward the end of the year. Frankly, you get this really odd result, that if somehow things slowed down, we actually produce cash. And if things speed up, we use a little bit of cash. But the expectation is that we will see an increase year-over-year on the line of credit. Just what number that is, is yet unclear.

Okay. And philosophically would you use that credit to buy back shares? Or share buyback would have to come from true free cash?

That's really an independent decision. In your model, have you considered the sale of flow back business? Just one clarifying point.

Yes. We've got that in our cash model.

Because that generates somewhere $40 million of cash pretax between the sale price and the working capital that we retain.

Thank you. That's all for me.

Jim Crandell, Dahlman Rose.

Welcome, Andy. And, Doug, I don't know if this is your last call but if it is, I wanted to wish you all the best in the future.

Thanks, Jim. I don't think you're getting rid of me quite that easily.

Good. You've done a very good job at Patterson. Couple questions which really I don't think have been asked, at least I haven't heard. Of your 15 newbuilds that you have this year, I know in the past that all of your newbuilds have had three- and four-year contracts. Do all of your 15 newbuilds this year have at least three-year contracts?

Yes, they do.

Jim, let me clarify. We're planning on 24. 15 are under contract. Those 15 under contract were all under three-year contracts.

All long term. Good. And do you sense at all, Doug, that there's any increase with any of your rigs that you put under contract in price competition to win this? Or did the major companies who have had newbuild fit-for-purpose rigs seem to all have the same pricing strategies?

We haven't seen a whole lot of change in pricing strategies. Maybe with the exclusion of one of the new people that have got into the newbuild business. I won't mention who they are, but they have a funny accent. But really, I think pricing has stayed relatively disciplined, I think, on newbuilds. We do wonder sometimes whether some other people are actually reducing the term commitment. But all of ours to this point are three-year contracts.

Good. Do you see, Doug, at all in the field, when you're drilling in horizontal wells, a desire among any customers to replace your electric SCR rigs, which might be a great rig, with an APEX rigs?

Jim, we really haven't seen much of that. There is obviously some people that like the new AC rig technology. There's just as many other customers that are quite happy with an SCR electric rig. And, in fact, we even had some very interesting debates on newbuilds with some customers that said -- Gee, I don't want all that fancy stuff. I'd like to have an SCR. It gets to be a very interesting debate, because certainly, we're very -- but, really, the last two or three years, all of our rigs have been AC. So we've seen very little impact on people really trying to replace existing very high-quality rigs. I think a big part of that is just the crews. And we do get sometimes people saying I wouldn't mind a new rig but I want the crews from that older rig. And we typically try not to do that.

Okay. And last question. We've seen some of your pressure pumping competitors literally have some horrific problems with logistics, including access to the 20/40 white sand and access to guar. You seem to have anticipated these shortages well. And I'm not aware of any problems in there. Obviously you must be paying higher prices, but --.

No.

Do you think it's foresight and locking in supplies? Or can you address that?

Jim, I really think -- trust me, we have the same sort of challenges and issues. I just think our guys have done a very good job of sharing between the markets. We do not pay higher prices than other people. I think because we're in really two very select markets, we've got the infrastructure in place, we stay very close to what our customers' needs and desires are. We've paid a lot of attention to this over the years. And yes, we've been close. I remember last fall when acid got in very short supply and the prices tripled, trust me, we were just as concerned about it as anybody. But fortunately we were able to get through that without any major issues. So to me it's a matter of paying attention and trying to anticipate what your customers are looking for.

Jim, I give our credit to our managements in both our pressure pumping in the Northeast and in the Southwest. They're both nimble, close to the field, and very adroit at running these businesses.

I tell you, you've done a good job in that area. Certainly your competitors, big and small alike, have had some horrible problems in terms of logistics. But congratulations, and again, welcome, Andy.

Andrea Sharkey, Gabelli & Company.

I just wanted to ask, I know you mentioned that you moved some pressure pumping equipment out of the Northeast and into the Southwest. So maybe could you just give us the split of how much horsepower is in each market?

Yes, Andrea, I think the reference to moved out wasn't really moved out. That was brought pumps and crews down to help with work in the Southwest where they were short people and equipment. And then when the work was completed, that equipment returned. So I think we can ship the equipment back and forth between the two regions. If you make reference to our annual report, I think the horsepower is still broken out as it was at that time.

Okay. Great. Thanks.

A little more than 50% in the Southwest.

And then in the Southwest, you said you might start to see some pricing pressure there as more equipment is moving in. How much in the Southwest is actually under these take-or-pay contracts? Is most of it spot market or do you have some that are contracted?

We have a couple that are contracted. But I'd have to say the bulk of our horsepower in the Southwest is really spot market, particularly in the Permian. We do have a big crew in South Texas that's under contract. And that's roughly 40,000-horsepower.

Okay. Great. And then are you hearing anything from the customers where you do have contracts primarily in the Northeast, and then the one in the Eagle Ford, are you getting any pushback from them where they're saying to you -- what can you do for us to make the cost lower or working less? Or anything where they may be trying to adjust the contracts?

We're having inquiries from our customers. In good times and bad, they're always asking us for what we can do to give them better service and more efficiency. And so that's part and parcel of being a service company. So yes, we're having those conversations. Lower prices for natural gas obviously probably intensify those conversations but those are a regular part of our business.

Okay. That's very helpful. And then just my last question. You guys mentioned that you feel that you'll see some improvement in the second half on pressure pumping. I'm not sure if I misheard that. If that's correct, I was just curious maybe what is giving you the confidence to think that things will get better in the second half.

Andrea, I mentioned earlier we have some very customer-specific issues in Q2 that we do think are going to reverse themselves in Q3 and Q4. And it's really driven by the demand for oil in the crude oil basins, as opposed to necessarily the natural gas market.

Okay. Great. Thanks so much. That's really helpful.

Kurt Hallead, RBC Capital Markets.

I was wondering if you guys, if you haven't already outlined it -- I hopped on a little bit late on the call, I think I got early on the Q&A -- but I just wonder if you guys could outline for us what percentage of your land revenue is contracted for in 2012? And what percentage of your pressure pumping revenue is contracted for 2012? Thanks.

Your question is on 2012, Kurt?

Yes, for the remainder of the year, what percentage of your potential land revenue is contracted for. And the same thing for your frac business.

I have the total backlog number. I don't think I have 2012's revenue number readily available to me. The backlog number, most of it would relate to '12. You have some in '13 but that was $1.7 billion.

That $1.7 billion, is that for land drilling and frac or is that just for land drilling? Can you separate it out for us?

That's just land drilling.

Okay. And what about for frac?

I don't have that number.

Okay. And then the follow-up question I would have, and we've all been through many of these varying cycles. Your stock is priced in like your earnings are going to get cut in half, which would almost imply that [free COW] would be have to get cut in half, as well. It doesn't appear that that's going to be the case with offsets on oil versus gas. Though we are hearing, in some basins that pressure pumping is now being priced at breakeven. So can you wrap this into a nice little package for us and give us your perspectives on where the cycle is. Where you think that thought process on the potential collapse in the business. And whether or not pressure pumping is being priced at breakeven levels and if you're participating in that practice? I know a lot of questions.

Let me try, Kurt, to break those into a couple of questions and see if I can answer your questions. First, I think we've tried to indicate, both in our press release and in our remarks this morning, how positive we feel in respect of the drilling business. As you, I think, correctly indicate, it seems as if from looking at our stock prices if people expect our rig count to have collapsed. We've had conversations with investors over a long period of time in which they've been very concerned about this. But as you know, our rig count has continued to go up, in the first quarter. Continued to go up in first quarter. And looks to be pretty stable right now going forward. So we don't really understand where the investors are coming at this skepticism, vis-a-vis the US land rig market.

In terms of the pressure pumping industry and the pressure pumping business, we obviously see the effects of the decrease in activity driven by lower natural gas prices. And the effects caused by, in effect, the building of new equipment that occurred when people expected to get very quick paybacks. At this point, there's a move in the market for a rationalization. We don't believe that the market is going to remain at a breakeven point for any length of time. We think those kinds of things can happen from time to time, but we don't see that as a long-term trend. We think we and others in the business will be disciplined about our behavior in the business. And we'll expect to make good returns from our equipment in that industry. And so fundamentally, we see this as a period of time during which that industry will become rationalized. That is, pressure pumping. And that it will join our US drilling industry and be quite strong. Obviously I've left out Canada because we're expecting the seasonal decline in the second quarter. But we think that bounces back, as it usually does, come summer. The last thing I'd say is we're not pricing our pressure pumping equipment at breakeven.

Okay. I don't want to keep anybody else on the call too much longer. But Doug, you mentioned Permian not being back to where it was in '07, '08. That's to me, just hard to imagine, given the fact that $100-plus oil for the last couple of years, the economics of that basin probably being pretty robust. The dislocation that's been happening from gas/oil, I would think that E&Ps would want to get there as fast as they can. So what's the bottleneck? Is it they don't have the acreage lined up? Can you give us some color on that?

Kurt, I think there's a lot of reasons for that. Certainly people is one of them. I'm not sure where the people have gone that were working in the industry in 2008. But there is certainly way more pressure on people today. But I also think it takes different kind of people. Drilling the horizontal wells, both in terms of equipment and people takes some different skill sets. And I think, quite honestly, just in terms of proving out some of the horizontal plays that people are drilling today, it takes time. It just doesn't ramp up quite that quickly. I think we all thought that a lot of this technology would shift from basin to basin with ready ease. And I think it just takes a little bit longer to figure out some of these plays than people think it should. We all wish it would happen quicker. But from our perspective, you've got to do this in an orderly fashion, particularly to keep your service quality up.

Kurt, I don't know what the national employment figures or unemployment figures are these days, but I promise you that whatever the national number is, whether it's 8% or 9%, it's not 8% or 9% in Midland.

Thanks. Appreciate it.

And there are no further questions in the queue. I would now like to turn the call back over to Mr. Mark Siegel for closing remarks.

I'd just like to thank all the participants for their participation. And look forward to speaking with you again at the end of the next quarter. Thank you, everybody.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a wonderful day.