James Michael Drickamer - Director of Investor Relations Mark S. Siegel - Chairman of the Board and Member of Executive Committee Douglas J.

Wall - Chief Executive Officer and President John E. Vollmer - Chief Financial Officer, Treasurer and Senior Vice President of Corporate Development

Robin E. Shoemaker - Citigroup Inc, Research Division Scott Gruber - Sanford C.

Bernstein & Co., LLC., Research Division Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division J.

Marshall Adkins - Raymond James & Associates, Inc., Research Division Waqar Syed - Goldman Sachs Group Inc., Research Division David Wilson - Howard Weil Incorporated, Research Division John M. Daniel - Simmons & Company International, Research Division Brian Uhlmer - Global Hunter Securities, LLC, Research Division James D.

Crandell - Dahlman Rose & Company, LLC, Research Division Andrea Sharkey - Gabelli & Company, Inc. Kurt Hallead - RBC Capital Markets, LLC, Research Division

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 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 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 regulation 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.

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 are 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 basins.

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 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 5 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 noncore 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 want 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 U.S., 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 one rig to 13.

In the U.S., 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 market 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 market. Although we lost some operating days associated with these moves between markets and customers, we feel the rigs are now in better market, 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 U.S.

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 cost 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 rig continued to work at near-full utilization level. Additionally, we believe that our fleet of highly capable mechanical rigs are ideally suited for the markets in which they are working, with almost 3/4 of our active mechanical rigs drilling in either the Permian or the Mid Continent.

Looking forward, we expect the rebalancing of the rig market to continue, with additional rigs moving from dry gas to oil and liquids market. With the movement of the rigs in the first quarter, we now estimate that approximately 68% of our rigs are drilling well for oil or liquids-rich target.

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 3 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 6 months, we are now reporting our term contract information in this same manner. In terms of our newbuild program, we completed 5 new Apex rigs during the quarter.

While newbuild conversations with customers have slowed, we signed 2 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 basin and become available in the spot market without a long-term commitment.

We believe this impact is dampening the near-term demand for newbuild. 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 U.S. and one in Canada.

Although additional new Apex rigs will be completed in the second quarter, our expectation is that our U.S. rig count in the second quarter will remain essentially flat due to the loss of rig days, as rigs transition between both customers and market.

Average revenue per day is expected to be flat in the U.S., 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 level.

This reflects a more than $100 per day improvement in the U.S. 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 2 regions we compete in tell a vastly different story.

The Southwest market remained 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 cost and cost of products continue to be a challenge, but we were pleased with our ability to manage these accordingly which led to our improvement in margin.

Unfortunately, we are now seeing an influx of equipment and new competitors in these 2 markets, and have already seen a much more competitive marketplace with the resulting 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 moving 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 due 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 market 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 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 2 regions, our established infrastructure has allowed us to avoid some of the logistic 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 earnings quarter -- the quarter's earning. 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 2 or 3 quarters, as reduced demand in dry gas basin, the influx of new equipment and competitors and the 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'm 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 2 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 U.S. rig business.

In the near term, we may see some lost day 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 of 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 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 pump equipment on order until demand improves.

It's important to note that we are not a new entrant in the Pressure Pumping business. We have 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 2/3 of our fracturing horsepower less than 5 years old.

Despite the uncertainties in this business, and the impact these uncertainties have had in our stock price, we believe the Pressure Pumping business has substantial long-term value. As Doug mentioned, we are planning to first have 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'm 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.

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. I think, we didn't mention this time, but we have about 155,000 horsepower committed under what we call term contracts in the Pressure Pumping business.

Now those contracts are proceeding and we certainly had some conservations 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're 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 contract.

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 rig, or sorry -- that fleet of Pressure Pumping equipment?

Or idle it and reduce your costs associated with that?

Well, the 2 markets are very different. What we 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 5 crews into 4. 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 6 crews in the Marcellus operating at 30% utilization if we can do that by -- if we can accomplish the utilization or the activity with 4 crews and reduce the cost, then that's what we will do.

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 5 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 of scenarios where we will flesh 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 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 sort of late in 2013.

Okay, good coverage there. And returning 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. But certainly, we'll 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.

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's 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 of 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 in the revenue, I believe that was quarter-on-quarter, how much of that is going to be pricing versus utilization driven by things like this shutdown?

Joe, I'm not sure we can really answer that. Obviously, it's a mix.

We’ve tried to put some -- 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 that 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 take talking rigs or Pressure Pumping?

Sorry. 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 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 of to buy back stock and we are considering it.

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, and 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 the, 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're starting to see some added pressure on pricing and even in the oily market. And what's going to be interesting, I think, is just to see how much equipment either gets idled, deferred.

We're going to -- 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 2 of some choppiness from 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 increased supply and now oversupply of equipment.

And then I suspect that as demand continues to increase, we'll see a meeting of the 2. And that's what I think is 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.

There's more discipline 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.

That's good color. How much of your equipment is parked on the fence today?

I mean, I know that the next 110,000, you're going to park on the fence, but any sense on how much is already parked on the fence?

Our own or the industry?

Your own. Yours.

Well, all of the equipment worked in Q1, Marshall. It's just, particularly in the Marcellus, probably on any particular day, we may have 3 or 4 out of the 5 or 6 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 out there. And there's some efficiencies, obviously.

Those frac crews are kind of 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. All right, last question from me.

You have roughly, it looks like 2/3 of your rigs under what we'd call longer-term contracts. Do we think that number, that percentage, is going to go up or down over the next year?

And what's your current outlook for the 9 that aren't contracted? Are you getting decent inquiries?

That the ones that are going to be delivered?

Well let me handle the second part first. Even though I said that discussions have slowed, we're still having conversations with people.

But I think the real key there is there's a lot of customers that are somewhat unwilling to sign a 3-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 9? 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, I mean, 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 kind of what I was getting to. Is that sound?

I think that's probably true.

Marshall, I think maybe you're putting it slightly differently, as I think I’d say, we think demand for newbuilds remains strong. But demand for contracts has perhaps slowed.

Just a question shifting to the Drilling side and on the [indiscernible] 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 like maybe 3 to 6 months’ time for, I mean, 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 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 3/4 of our rigs that you're talking about here are either in the Permian or the Mid Continent, which are very, very strong markets, I don't see them being further replaced by rigs coming from other regions.

Okay. And 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 industry, why not continue to build rigs for that at the current pace?

Well, 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 to accelerate that in the second half of the year to a 30 rig delivery schedule, and what we've basically decided is it seems prudent in this market environment to do to stay at the 25 kind of rate and we've come to a 24 as the logical number for this year in light of where we are currently. So we really see it as kind of 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 kind of 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's certainly some nervous in the Canadian market.

I think primarily with gas pricing. But interesting enough, I think Canada has seen the same shift to -- a big chunk of the rigs in Canada are now drilling for either oil or in certainly in the oilier market.

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 by Q4 we'll 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. 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.

Quick follow-on question, Doug, you mentioned customers waiting for the high-spec availability, the drill off in the spot market or roll in spot market rather than going for newbuilds with longer commitments. Have you -- does this portend the day rates to be pressured?

I know we haven't -- you said, you just said that we hadn't seen the evidence yet, but how should we interpret this from a day rate 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 they kind of create the floor or the ceiling if you will, I think that, that will remain, those day rate 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 do -- 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 think -- I don't think you're going to see any huge pressure on day rates and it's really going to be driven by the fact that there's still a very high demand for the 1,500 horsepower high-spec rig.

Great. And then just a quick follow-on on there, 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?

Well, I’d have to say we'd 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.

Just 2 questions for me. The first one is with much of the new frac equipment being idle, how do you see your RNM [ph] 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 and defer maintenance and swap it out with a new pump or would you still -- is there a way you can cut cost that way and 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, I guess, 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 on to the rig pricing for a second.

But if we can go back and think about the evolution of say, Pressure Pumping, right. We first started hearing about the pricing concessions last August but that was limited to the gas markets.

Then I guess, 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 unfolding with Drilling.

Because it seems like we're hearing about some pressures from some of your peers with the rig rate decline from the gas regions but the oil market's holding up. Do you think a similar patterns plays out during the next 6 months?

I think bracing on the Drilling side is 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 1,500,000 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 idle, is there a specific metric you're employing as to when it gets reintroduced or is this really more of gut feel based off customer conversations and value inquiry? 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 kind of look at things.

It's hard to look at past financial data and kind of say, oh, I'm going to make my decision based on that. You pretty much have to go on what the customer and your gut’s telling you about where it's going to be for the next couple of quarters.

A couple of quick questions. When we're talking about land rigs and deferral of the 6 rigs, is that semantics or is there anything to -- that they can’t be canceled?

Or is there any type of penalty or payments 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 draw works and have masts and subs built by various suppliers.

Once we commit to that rig, roughly half 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 will have varying degrees of being able to save the latter part of that $10 million.

Now we have not talked about canceling anything. We're at this point, what we’re talking about is deferring some of this year's rigs really into the 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, right. And same question for the Pressure Pumping, the 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?

Well, we don't typically do the final assembly ourselves. We do buy pretty much finalized equipment.

In some cases, you can -- because there's different suppliers to put together a fractor, 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 kind of put the pump and the engine and the part converter altogether on the trailer.

Makes sense. Quick question on cash taxes.

What's your estimate for your percentage tax. Is your tax going to end up as a cash tax in 2012?

Correct 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 and kind of 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 for this year, and I'm not getting that number. I'm just trying to rectify those 2 numbers.

Aren't those pretty even to potentially cash negative throughout 2012 in your view?

Yes. Going into the year, our expectation was that we would borrow on our line some of -- the big factor I think is going to be how much investment is there on 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 slow down, we actually produce cash and things speed up, we use a little bit of cash. But anyway, the expectation is that we will see an increase year-over-year on the line of credit.

Just what number that is, it's 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 the flowback business?

Just want to clarify a point.

Yes, we've got that in our cash flow.

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

A couple of 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 3- and 4-year contracts.

Do all of your 15 newbuilds this year have at least 3-year contracts?

Yes, they do.

Jim, yes. Jim, let me clarify.

We're planning on 24, 15 are under contract. Those 15 under contract are all under 3-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 has kind of 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 3-year contracts.

Good, 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 rig?

Jim, we really haven't seen much of that. There's, 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 -- really, the last 2 or 3 years, really 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 that 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 [ph] white sand and access to guar [ph] and 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, no.

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

Well, 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 2 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 mean, 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 kind of get through that without any major issues.

So it's just to me, it's a matter of paying attention and trying to anticipate what your customers are looking for.

Jim, I’d give our credit to the -- our managements in both of our business, both in Pressure Pumping in the Northeast and in the Southwest. They're both nimble, close to the field and very adroit at running these businesses.

Well, but they’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.

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 where -- of how much horsepower is in each market?

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 of people and equipment.

And then when the work was completed, that equipment returned. So I think we can shift the equipment back and forth between the 2 regions.

If you make reference to our annual report, I think the horsepower is still broken out as it was at that time. A little more than half 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 that 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 costs lower or working less?" Or anything where they are maybe trying to adjust the contract?

We're always 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. I think, 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?

Well, 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 and in the crude oil basins as opposed to necessarily the natural gas market.

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'm just wondering 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?

Your question's on 2012, Kurt?

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 as a revenue number readily available to me. The backlog number -- most of it relate to '12, some in '13 but that was the $1.7 billion.

But that $1.7 billion is that for land drilling? Or and frac?

Is that just for land drilling? Can you separate it out for us?

That's just for land drilling.

Okay, and what about for frac?

I don't have that number.

Okay, and then just a follow-up question I would have, we've all been through many of these earnings cycles. Your stock is priced in like your earnings are going to get cut in half, which would almost imply that free count would have to get cut in half as well.

Doesn't appear that that's going to be case with the offsets with oil versus gas, that we are hearing in some basins that Pressure Pumping is now being priced to breakeven? So can you kind of wrap this into a nice little package for us?

And give us your perspectives on where the cycle is? Where you think the ball [ph] prices 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, so...

Yes. Let me try, Kurt, to break those into a couple of questions and see if I can answer your questions.

First, I think we have 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 for 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 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 sort of where the investors are coming at this skepticism vis-à-vis the U.S. land rig market.

In terms of the Pressure Pumping industry, and 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 that 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 sort of see this as a period of time during which that industry will become rationalized, that is Pressure Pumping, and that it will join our U.S.

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.

I guess, last thing I'd say is we're not pricing our Pressure Pumping equipment at breakeven.

Doug, you mentioned Permian not being back to where it was in '07, '08, that to me is hard to imagine, given the fact that $100 oil plus for the last couple of years, the economics in that basin probably being pretty robust, the dislocation that's been happening from gas oil, I would think that the 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?

Yes, I think, Kurt, I think there's a lot of reasons for that. Certainly, people was one of them.

I'm not sure where the people have gone that were working in the industry in 2008. But there's 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, take 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 mean, I think we all thought that a lot of this technology would shift from basin to basin with readily -- with ready ease, I guess, 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 whatever the national number is, whether it's 8% or 9%, it's not 8% or 9% in Midland.

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