Patterson-UTI Energy Inc (PTEN) 2011 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2011 Patterson-UTI Energy, Inc. conference call. My name is Gina, and I will be your coordinator for today.

At this time all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (Operator Instructions).

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today, Mr. Mike Drickamer, Director of Investor Relations.

Thank you, Gina. Good morning, and on behalf of Patterson-UTI Energy I would like to welcome you to today's conference call to discuss the results of the three and 12 months ended December 31, 2011.

Participating in today's call will be Mark Siegel, Chairman; Doug Wall, President and Chief Executive Officer; and John Vollmer, Chief Financial Officer.

Again, just a quick reminder that statements made in this conference call will state the Company's or management's intentions, beliefs, expectations or predictions for the future are forward-looking statements. It is 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 planned 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 material, supplier issues, weather, loss of key customers, liabilities from operations, government regulations, inability 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 is my pleasure to turn the call over to Mark Siegel for some opening remarks.

Mike, thank you. Good morning, and welcome to Patterson-UTI's conference call for fourth-quarter 2011. We are pleased that you're able to join us today. As is customary, I will start by briefly reviewing the financial results for the quarter ended December 31, as well as for the full year 2011, 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 to questions.

As set forth in our earnings press release issued this morning, we reported net income of $87.6 million or $0.56 per share for the fourth quarter ended December 31, 2011, and $322 million or $2.06 per share for the full year 2011.

EBITDA for the quarter improved to $272 million, marking the 10th consecutive quarter of EBITDA growth. The financial results for the fourth quarter include a pretax impairment charge of $11.3 million or $0.05 per share related to the previously announced retirement of 31 drilling rigs. For the full year 2011 we retired a total of 53 drilling rigs as part of an ongoing process by which we evaluate each rig in our fleet. As a result, we incurred an impairment charge of $15.7 million, or less than $300,000 per rig.

While we saw sequential growth in both of our core businesses, the growth was primarily attributed to the contract drilling segment. This segment, which accounts for approximately two-thirds of our revenue, benefited from increasing rig activity driven by continued strength in the oil and liquids-rich plays.

We have now witnessed through December, 30 consecutive months of growth in our US rig count. That is starting in July 2009. And I'm very pleased to tell you that our rig count continued to increase in January.

Additionally, the contract drilling business benefited from cost control initiatives that were geared towards reducing the costs that negatively impacted our third quarter. These cost reductions, combined with a $370 per day increase in average revenue per day in the US, lead to an increase of $770 in average rig margin per day in the US.

Although pressure pumping revenue grew by 7% in the quarter, we were disappointed by our results in this segment. At the outset I want to relate that our Southwest region performed strongly in the fourth quarter and is continuing to perform well in the first quarter. In the Northeast, however, a variety of factors impacted our pressure pumping revenue growth, including certain customer-specific delays and less demand for short notice work late in the quarter.

The Northeast pressure pumping market has remained soft in January, but all crews are currently scheduled to be active by the end of the quarter. In his remarks Doug will provide some additional details about this segment, but I do want to add that we think we have seen a shift to greater seasonality in the pressure pumping business in the Northeast, as both customers and the local authorities in respect of roads are more wary of high activity levels during the most difficult winter weather.

Overall, in 2011 we achieved growth in both contract drilling and pressure pumping, reflected in a 75% increase in revenue and a 176% increase in net income, which result from the investment we have made in both our people and our equipment. In total, in the past two years we spent approximately $2 billion on equipment. This investment furthered the transformation in our Company with the addition of 44 new APEX rigs and approximately 470,000 horsepower of pressure pumping equipment.

In 2012 we expect to spend approximately $1.1 billion on CapEx, which includes the construction of 30 new cap APEX rigs and 140,000 horsepower of pressure pumping equipment. We expect to fund this capital spending largely through internally generated cash flow.

Considering this level of CapEx for 2012, we expect depreciation expense for the full year 2012 to be approximately $520 million.

Before I turn the call over to Doug, I want to address concerns about low natural gas prices at this point in the year. We, like everyone involved in the North American energy industry, appreciate concerns heightened in the past 30 days about stubbornly high production levels, high inventory levels, and the resulting low natural gas prices.

From our perspective what we are seeing is a continuing trend of rigs and pressure pumping equipment migrating from dry gas areas to oil and liquids-rich areas. The relative strength in these oil and liquids-rich regions has absorbed, at least for Patterson-UTI, rigs that have been released from dry gas markets, and we expect this will continue this year.

Moreover, in pressure pumping the majority of our fracturing horsepower is located in oil and liquids-rich areas. In addition, 30% of our fracturing horsepower is under take-or-pay contracts.

Finally, term contracts and equipment quality should mitigate a significant amount of the risk for Patterson-UTI arising from a downturn in activity for dry gas, and we see 2012 as being another strong year for the Company.

I will now turn the call over to Doug.

Thanks, Mark. I will start this morning with some commentary on the drilling company before turning to pressure pumping. Demand continued to remain strong for our drilling rigs during the fourth quarter, as our average number of rigs operating in the US increased sequentially by 11 to 220 rigs, while our Canadian rig count was relatively flat at 12 rigs.

The increase in the US rig count was driven by the seven new APEX rigs completed during the quarter, as well as the activation of additional conventional rigs. In total we completed the construction of 25 new APEX rigs during 2011 and we remain on schedule to increase our production to complete 30 APEX rigs during 2012. We now have long-term contracts for 13 of the 30 APEX rigs that we plan to build during 2012, and see additional newbuild demand primarily in the oily markets.

Despite the very recent weakness in natural gas prices, demand for our rigs continues to be strong. We averaged 241 rigs during the month of January, 225 in the US and 16 in Canada. For the first quarter of 2012 we expect a further increase in our operating rig count to approximately 242 rigs, including an average of 227 in the US and 15 in Canada.

Let me address our exposure to the dry gas market, which we think will be mitigated by a number of factors. First, we continue to see a migration of rigs from the major natural gas plays to the oilier and the high liquids plays, and we expect this migration to continue.

Secondly, approximately 60% of our rigs active today in the US are committed under long-term contracts. Although some of our competitors use a different standard, it is important to note that we define a term contract as having an initial duration of at least 12 months.

Including only contracts already in place, we expect to average at least 120 rigs under term contract in 2012, including an average of 131 during the first quarter. This 120 rigs under term contract is up 96 from our last conference call -- or up from 96 on our last conference call.

Finally, we estimate that roughly 60% of our rig fleet is drilling either oil or liquids-rich wells. Our greatest exposure to dry gas is within our East Texas and Marcellus regions. In the Haynesville we currently have 23 rigs drilling for gas, 12 of which are under term contract. While we expect that only a handful of the 11 rigs in the spot market will move to other markets, primarily more focused on oil or liquids-rich activity, let me point out that all 11 of the spot rigs in this market are 1,000 horsepower or greater, and therefore, we think they're in the sweet spot of demand for other markets such as the Permian, the Eagle Ford or Midcontinent.

In Appalachia, which includes both the Marcellus and the Utica Shales, our term contract coverage is even stronger. 29 of the 34 rigs drilling in this market are currently under term contract. Just as important, four of these are drilling in the liquids-rich Utica and another 15 are drilling in the more liquids-rich targets in Southwest Pennsylvania. Of the remaining 15 rigs drilling in Northeast Pennsylvania, only two are in the spot market.

We are not expecting a meaningful decrease in our drilling activity in Appalachia, given our low spot market exposure. Overall we feel quite confident that our term contract position and the uptake of spot market rigs from the dry gas areas to the liquids-rich plays will keep our activity level strong.

Let me make a couple of quick comments on the revenue and cost side relating to the quarter. Average revenues per operating day for the fourth quarter were $21,980, a sequential improvement of $540 per day. Rig pricing continued to improve during the quarter, and the impact of newbuild contracts helped push our revenues higher.

While we had some unusually high repair and maintenance costs during the third quarter, I am pleased to say that our average direct operating costs decreased by [$280] per day to $12,700 for the fourth quarter. Direct operating costs in our US land business were actually down $400 per day, but the overall decrease is lower than this due to the normal winter cost increases we experience in our Canadian business.

For the first quarter we anticipate an increase in the average revenue per day of approximately $350, partially offset by an expected increase of $200 per day in operating costs. While we're not prepared to speak to the second quarter in any detail, please let me remind you that historically the second quarter has been impacted by the seasonal breakup in Canada. Historically we have averaged about two rigs in Canada during the second quarter.

Before I turn the discussion to pressure pumping, let me make a few comments on the announcement regarding our retirement of the 31 rigs during the quarter, bringing our total rig retirements for the year to a total of 53 rigs. In our fourth-quarter rig assessment we determined an additional 31 rigs would no longer be marketed, and they have now been retired. Certain parts of these rigs have ongoing value, and the parts have been transferred to inventory to support our remaining rig fleet.

Of the 31 rigs, the average horsepower rating was 735 horsepower, a segment of the market where demand is the weakest. Overall in our assessment we determined it made no sense to refurbish or spend any incremental capital on these smaller type rigs.

So turning now to the pressure pumping segment, as Mark mentioned earlier, the growth in this segment fell short of our expectations. Revenues for the quarter increased approximately 7% sequentially to $241 million. EBITDA for pressure pumping totaled some $72 million for the quarter, up slightly from Q3. EBITDA for the full year in our pressure pumping business totaled some $267 million.

Late in the quarter we began to see some utilization issues in the Northeast market. The quarter finished on a rather weak note as we were hit very hard by the Christmas and holiday shutdown. In addition, a number of our customers in the Northeast had a combination of location issues, wellbore and other drilling issues, and some operator-provided water issues, which caused numerous delays and pushed a great deal of work into the first quarter. Unfortunately, some of the above delays impacted our January activity as well.

The advent of large horizontal fracs has fundamentally changed our business, particularly in the Marcellus. For the second year in a row we have witnessed a slowdown in the fourth quarter and well into the first quarter, as our customers continue to grapple with logistics issues related to completing these types of wells in the wintertime. In general, the inefficiencies and the higher cost brought on by the winter weather are creating a new seasonality effect in the Northeast.

In general, I believe it is fair to say that the Northeast market has changed considerably over the last couple of years. It appears the backlog of work waiting on completion has declined substantially, providing fewer options for short notice work. Having said all this, our customers are indicating increased demand late in the first quarter and all of our frac crews are scheduled to be active by the end of the first quarter in this market.

Turning to the Southwest region, our activity levels remain strong. And while we do expect some additional equipment to enter the Southwest market, we do expect the strength in this market will continue.

Operating costs in both regions continue to increase and are pressuring our overall margins. The cost for labor and materials, and in particular sand and hydrochloric acid, as well as logistics costs, continue to weigh on our overall margins, although we believe these costs will level off.

During the quarter our pressure pumping supply chain management did an outstanding job of avoiding many of the logistics issues that have impacted the industry. During the fourth quarter we took delivery of 58,750 horsepower, although I must say it had little or no impact on our revenues for the quarter as the deliveries occurred very near the end of the year. It did, however, have an impact on our costs as we hired and trained crews to run this equipment.

In total, we took delivery of approximately 200,000 horsepower during 2011, and ended the year at approximately 631,000 total horsepower in our fleet. During 2012 we expect to take delivery of an additional 140,000 horsepower, all of which is expected to be delivered by the end of the third quarter.

We currently have 155,000 horsepower under take-or-pay term contracts, roughly split evenly between our two markets. We do believe we will continue to see some equipment move from the dry gas market to meet the unsatisfied demand in the oilier basins. Just as we did last summer in moving equipment out of the Barnett, we will continue to move our equipment and our people to the markets where we can maximize utilization and generate higher returns.

With respect to the first quarter in our pressure pumping business, both revenues and margins continue to be impacted by the winter slowdown and inefficiencies resulting from this lower utilization in the Northeast. We are expecting pressure pumping gross margin percentage will be about 30% for the first quarter, while pressure pumping revenues are expected to be similar to the fourth quarter. We do expect a seasonal recovery in the second quarter.

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

Thanks, Doug. As we conclude our prepared remarks, the message I would like to leave with shareholders is that as a result of the transformation our Company has undergone over the past several years, we believe we have substantially lessened our exposure to cyclical downturns. Despite the slowdown in natural gas-related activity, we are optimistic that 2012 will be a good year for the Company.

Let me tell you why. First of all, approximately 60% of our fleet is currently drilling oil or liquids-rich wells. Second, and more importantly, we have made significant investments in high grading the quality of our rig fleet. We ended 2011 with 91 APEX rigs in our fleet, more than three times the number we had in our fleet three years ago.

These investments have allowed us to significantly increase our term contract coverage as we currently have approximately 60% of our active rigs operating under term contract, almost three times the term contract coverage we had three years ago.

Finally, our pressure pumping fleet is about 5 times the size it was three years ago. More importantly, our pressure pumping business has expanded geographically over this time period and substantially increased our exposure in this business to oil and liquids-rich markets. In short, we are positive in our outlook for 2012. If the industry remains strong in 2012 we think we are very well-positioned to benefit.

In that respect let me tell you we have the addition of 30 new APEX rigs in 2012, which will likely increase our average daily revenue. Second, with the strength of our balance sheet we can be financially opportunistic in continuing to grow the Company while pursuing other options if our evaluation continues to remain depressed.

With that I would be remiss if I did not thank the men and women of Patterson-UTI, many of whom are on this call today. Your hard work, combined with your focus on safety and customer service, make this Company strong, a company we can be proud of.

Operator, we would now like to open the call for questions.

(Operator Instructions). Jim Rollyson, Raymond James.

Doug, a couple of questions, I guess, on the rig side -- 30 new rigs this year on top of 25 last year, and 140,000 of pressure pumping capacity. Can you give us some sense of what your schedule is for that delivery for this year?

It is pretty evenly broke down, but certainly on the rig side we are looking at really a little on average of about seven a quarter. It varies a little bit depending on customer requirements and when they're looking for the rigs, but in terms of just giving you some guidance, it is pretty much evenly split through the year.

And in my comments that on the frac horsepower it really is frontend of the year loaded. We expect to have all of that equipment delivered, put together and hopefully working early in the third quarter.

Helpful. Last year in your earlier comments before this quarter were also you were reactivating or refurbing rigs at something like around one a month. Thoughts or plans for reactivations for 2012?

We really don't see a whole lot of refurbishment of further rigs this year. We do expect there will be some reactivation through the year. A lot of that really will depend on natural gas pricing. But we certainly have identified some limited number of rigs that if things still progress that we would consider reactivating, and would require a minimal amount of capital to put back to work.

Understood.

But I don't see the levels being as many as we did last year.

Understood. On the retirement side of things, you've retired a few rigs for each of the last couple -- two or three years anyway. Do you think you are mostly through rigs that are under consideration for retirement at this point?

This is John. Every quarter effectively they are evaluating the rig fleet. I think there were roughly 50 last year. The year before that I think there were four or five. So it is really dependent on the demand for the rigs and the state of the rigs as time passes.

All right, and last question for me. Just curious what your customer commentary has been about any possibility for the rig markets that you guys have exposure and maybe have contracts in like the Haynesville, for example, about your customers' desire to relocate those elsewhere?

That has been a fairly recent occurrence, I guess, with most of the markets that I think people are concerned about. The customers seem to alternate from week to week as to what their plans are. To date we have seen very little impact or even people getting serious about moving rigs from market to market.

I would like to mention, I say in both those markets that I think people refer to the most, the Marcellus and Haynesville, we have very strong long-term contract coverage. And I think people recognize that those are take-or-pay contracts and so we haven't really to this point had many discussions about moving the rigs somewhere else.

Good, thank you.

Joe Hill, Tudor, Pickering, Holt.

Doug, I was wondering if you could comment about operators' appetite for term contracts today, both on new equipment and renewals of older equipment. I noticed you added a fair number of term contracts during the quarter, and I was just wondering what kind of look you can give us real time as to demand for that?

We told you on our last call that typically the fourth quarter you see a little bit of a lull. I am pleased with the number of newbuilds that we signed up since our last call, and also with the ongoing demand we see for newbuilds in the marketplace, so we're pretty pleased there.

I think on the drilling side it is about falling into place like we thought it would. No question that it has been a much harder sell on the pressure pumping side. We have -- certainly we have pieced together some things that we will keep some commitments on -- some pressure pumping equipment. And we're still having discussions with people about further term commitments.

Then on the third-quarter call, Doug, you gave us some indication that frac price discounts improved about 4% in the Southwest. Can you give us an update on what pricing is doing in pressure pumping for the Southwest and the App region this quarter?

The frac prices certainly across the quarter in the Southwest remained pretty stable. They improved slightly, but not enough to make a big deal out of it. We certainly have seen a little bit more (technical difficulty) in pricing in the Northeast than we have in the Southwest. But I would still say in the Southwest markets there is still improvement for pricing in that particular market.

Then, Mark, you intimated that you have some balance sheet options if the valuation remains depressed for the equity. What exactly would trigger some sort of movement on your part to do something and what would that look like?

Every quarter our Board considers our balance sheet and considers in effect our strategic options and we consider where we are in the market. And I guess I feel as does most of the Board, I think, that it is an appropriate thing for us to think about each quarter. And really what I wanted to make sure the investors understood is historically we have had -- we have bought back stock. We have had a dividend. We have been pretty consistent about all of these things, and I just want to make sure that the shareholders remember that the Directors are aware of it and think about it every quarter.

Fair enough. I will turn it over. Thanks.

Dave Wilson, Howard Weil.

Just kind of a follow-on regarding the rigs, the newbuilds, and the 17 that you have left uncontracted. Are you fairly confident -- it sounds like, Doug, that you're going to be fairly confident that those will be delivered into the market contracted. Is that a fair -- from what you are seeing is that a fair assumption?

Yes, I think that is very fair.

And any guess between those going into the market, whether it is an incremental rig or maybe a replacement of a rig that is rolling off a contract or anything like that, or do you think these 17 will be a true incremental add to what is working right now?

Well, what we have seen so far have been true incremental rigs for us. I will say that we have replaced some other competitors in the marketplace. I think our customers continuously go through a process of evaluating performance. And I do know of the 13 we have already signed, I think four or five of them are specifically replacing somebody else's rigs. But in our own case, we think it is all pretty much to this point going to be incremental.

Okay. Then switching over to pressure pumping. Comments this far this reporting season regarding pressure pumping have been, in my opinion, from matter-of-fact to slightly optimistic. I was wondering based upon your prepared remarks just saying that you guys fall into the matter-of-fact camp an accurate statement, or do you think you would characterize your view of the market as slightly more optimistic?

I would say -- it is interesting to hear you characterize it as A or B. I think that we are optimistic about the marketplace based on the view that says that we expect more frac stages in 2012 than in 2011. So that is a reason for our optimism about the marketplace. On the other hand, we are aware of what is happening with natural gas prices and we want to be judicious about the marketplace given that thought.

Sure. So, Mark, along those lines what gives you the most angst on pressure pumping. Is it crewing up or is it maybe [really] dislocations from having equipment migrate from one area to the other, but it doesn't sound like that is really happening? What when you look at that space gives you the most angst?

I guess maybe the right answer is we have been doing this for a long time, this management team. We're very experienced at going -- being able to respond to the marketplace. One of the, I think, hallmarks I hope of our team has been that we have been nimble. And my own reaction to it is that to the extent to which there is change in a market, whether it is geographic, whether it is a commodity, whether it is -- regardless of what the cause of the change is, I think we're pretty comfortable that we will be able to evaluate the nature of the change and make a kind of smart response to it.

And, frankly, that goes to the beginning of the answer, maybe there is some matter-of-factness about it, because I think it is the sort of thing which this management team has had a fair amount of experience with, and so to whatever extent there is change, I think we can deal with it pretty well.

All right, thanks for those comments. Then one final one, Doug, switching back on the rigs under contract in 2020, the average of -- I'm sorry, 2012 -- the average of 120, how many of those are non-APEX rigs? I think I can back into a number, but I just wanted to make sure I was thinking about it the right way.

I don't have that in front of me. Of the 120 non-APEX -- I would suggest that virtually all of our APEX rigs are under contract. So I think you can pretty much say that 90 -- or close to 90 of the 120 are APEX rigs. The others would be non. It may be slightly higher than that, but virtually all of our APEX rigs are under contract.

Perfect, that is what I was thinking. Thanks for the time, guys. I will turn the call back over.

Scott Gruber, Bernstein.

A question on pumping in the Marcellus. You highlighted that the backlog of work was down. Have we completely eliminated the backlog -- of the excess backlog, I should say, of uncompleted wells? Has the backlog returned to a more normalized level relative to drilling activity?

I think that is a difficult question for us to give you a true answer. We believe the backlog of wells that are ready to go on a minute's notice has certainly declined. I would still believe there is probably a backlog of wells out there, but with various logistics issues like permits and regulatory issues, sand, all those things, a lot of people -- it takes a lot longer to get one of these locations or pads ready to go get fracked today, so I would say that certainly the backlog of wells that is just sitting there waiting for a frac crew has reduced. I couldn't really comment on has the true backlog of wells declined or not.

One of the things that we have been told is that we believe that some of the customers are trying to develop a pretty good backlog now during this winter drilling period. And, in fact, we will be fracking it, as we said, toward the end of the first quarter and into the better weather. That is one of the things that we see and one of the reasons why we are, in effect, saying what we have been saying about getting -- the crews being more active at the end.

Got it. So it sounds like it is just a bit of a timing issue here. Your ability to put your Appalachian crews back to work, does that also reflect moving crews out of the Marcellus and into the Utica, is there an element of that as well?

I think there is. We have done a few frac jobs over in the Utica, but to date there is only four or five rigs, I think, working in the Utica -- or 10, I think. We have four or five at any one time.

I don't think there is a substantial backlog of wells completed and ready to be fracked in the Utica to see full-time commitment for crews over there. We do believe that will come in the next year or so. But I think at this point we have not seen a lot of movement. You know, those crews will go over there and do a frac job and then head back to their base, which is probably in the Marcellus.

Got it. So your positive comments on Marcellus pumping reflect a resumption of activity within the Marcellus?

I think it is both, but certainly the Marcellus is the big driver there.

Got it. That is all for me. Thanks.

John Daniel, Simmons & Company.

Mark, you noted an expectation for more frac stages in 2012 than 2011, is that on the overall fleet or is that on per fleet?

That is a comment about the overall in the frac stages in the country.

Okay. One other. You guys have been pretty candid here on the pricing in terms of being down in the gassy regions. And as we try to reach out to some of the various private guys across the oily areas, they are increasingly noting the number of increased bidders on work, which would seem to suggest that pricing pressures are likely forthcoming in the next quarter or two in those areas.

Assuming that plays out, you guys have a lot of equipment coming on order. Does that more than offset -- the incremental equipment -- does that more than offset the pricing pressures such that margins can stay flat? How do you see this playing out?

I think a lot of that equipment from the time we ordered it and where we planned it might have ended up, I think we have changed our thoughts where some of the new equipment is going to go into those markets.

I do think you will see more and more equipment heading into the oilier market over time. Just as you suggested, I would suspect we will see some additional price pressure in those markets. But I think each case is almost a case by case. I still think there is an undersupply of equipment in markets like the Bakken. We think there is going to be more equipment taken up in the Eagle Ford, certainly the Permian in West Texas.

I think we haven't even seen the full impact yet of some of the drilling programs that got underway in 2011. So I think pricing is going to be very interesting in 2012. Obviously, as you know, pricing is dictated a lot by supply and demand in particular markets, and we expect a lot of these markets are going to be very dynamic in 2012.

Sure enough. One last one for me. If you guys are moving rigs, in the past when rig activity is robust the customer will sometimes pick up for the rig relocation, and when the cycle starts to change they start trying to push the burden to the driller. At this point as you guys are moving rigs, who is paying for it?

Typically to this point we have had the customer completely pay for both the rig move and all associated costs during that. I can't disagree with you. I would guess over time that there will be a little bit more and more pressure on that. And it depends how far you are moving things. If you're trying to move a rig certainly out of the Marcellus somewhere else, you may have to help a little bit with those costs, but we don't anticipate doing that.

Okay, fair enough. Okay, guys, thank you very much.

Kurt Hallead, RBC Capital Markets.

This is actually Justin sitting in for Kurt this morning. I had a couple of questions. One is on the pressure pumping side and one on the drilling side. I will start with pressure pumping. Just looking at the revenue per frac job in the quarter, it looks like it stepped up pretty nicely from the fourth quarter. Can you talk about some of the dynamics there that are impacting that?

Part of the issue there is it was a customer mix issue where we moved from not providing sand on jobs to providing sand on jobs. So you have to be a little bit careful with those revenue per job numbers. A lot of it is so highly indicative of the types of customers you are working for, and so I think that probably explains most of the difference there.

Got it. Okay. Just to clarify, is that a shift among customers or is that a change in the contract with an existing customer that is driving that?

It is probably a shift from customer to customer.

Got it, okay. And then just the next one on the drilling side. Looking at the cash margin progression, I believe you guys last quarter had guided to a $500 per day sequential increase with a combination of day rates and costs. And you obviously got both day rates and cost improvement, but the cash margin came in quite a bit better than what the guidance was. Can you flesh that out a little bit more and just talk about maybe where the biggest surprise was relative to the initial expectation?

Really it is on the revenue per day side. We accomplished more increase in revenue per day than we had originally thought at the time we commented in late October.

Got it. Okay. Thanks, guys. That is it for me.

Luke Lemoine, Capital One.

Doug, could you remind us roughly where your horsepower is located at this time? And are you currently moving any or do you have any mobilizations planned in the near future?

At the moment roughly -- and I will talk frac horsepower just because I think sometimes we confuse you with talking total horsepower. But of our high-pressure frac horsepower 47% of it is in the Marcellus; about 53% of it is in the Southwest. Of the 140,000 horsepower that is on order, we have yet to decide exactly where it is going, but I would think that you will see the big -- or the majority of that likely go into oily markets as opposed to the dry gas markets.

And then that 47% that is in the Marcellus, how much of that is in Southwest Pennsylvania roughly?

That is a hard question to answer, because that stuff moves around from job to job. As you know all that stuff is on wheels. But we do a significant amount of work in the -- what I'm going to call the higher liquids part of Pennsylvania.

Okay.

But, as you know, sometimes our crews from Punxy and from Williamsport, if we had more work down in the southern part where we -- certainly the oily and the liquids content is higher, those crews will move down there on a moment's notice.

So we typically -- it is hard to say that -- you know, when we put a frac crew out it is kind of a moving number. Sometimes we have two crews working out of places like Bradford, sometimes the next day it will be one.

Then, John, Mark had given us the D&A number for the year, could you help us out with G&A a little bit?

Yes, for the year I think it would just be a little under $70 million. It would be $69 million, somewhere thereabouts. And for the first quarter, I guess, it would be about $16 million.

All right, thanks.

Andrea Sharkey, Gabelli & Co.

I was wondering if you could talk about the 17 rigs that aren't contracted right now. I know obviously your expectation is that they would get contracted. But in the event that the market somehow rolls over and for some reason they don't get contracted, how easy would it be for you guys to pull back and not complete them or not build them?

Well, let me first say that we do expect that we will see term contracts signed on them. Since we started our newbuild program three or four years ago we have had a pretty steady quarter-by-quarter base of signing up new contracts. So we're pretty comfortable at this point that we will sign contracts.

But I hear your point. Almost monthly we have discussions about what-if, although we are not planning those what-ifs, they're certainly -- I guess if we chose to, we could certainly slow down or defer some of it. The way we build rigs, about half of the cost of -- the final cost of the rig is really equipment, the other half is rig-up cost.

So to give you a definitive answer really depends on how far along we are in that whole rig-up process. But certainly to answer your question, if we decided to shut things off today, yes, there could be a significant reduction in our capital plans. But having said that, I would say that is not the way we are proceeding today.

Sure, I understand that. And then, I guess, the only other question I have for you is some competitors have said they think the rigs that are most at risk are mechanical rigs and SCR rigs and things like that. So I was just wondering if you could refresh my memory on how many of your rigs that are operating now are those rigs?

And then I don't know if you can give the detail on how many of those mechanical type of rigs are under contract, not under contract, working in oily basins or dry gas basins?

This is John. I don't have the contracts by rig type, but 100% of our electric rigs are working today. The excess capacity we have today is in the mechanical fleet, and primarily sub-1,000 horsepower, although there are some 1,000 horsepowers that could be brought back to work here -- 1,000 plus. Doug, do you have anything to add to that?

I couldn't really add too much. I don't have in front of me a breakdown of the contracts. I think the one thing I would add is that a lot of the mechanical rigs that are working today are in the West Texas region. And we anticipate that demand for those kinds of rigs in that region will remain strong.

Okay, great. Thanks a lot.

Those rigs are particularly well-suited to that kind of work, and so we're not expecting to see a substantial drop in our conventional rig count unless there is a huge change in the overall rig count.

Okay, great. Thanks a lot.

John Tasdemir, Canaccord.

I guess one of the things I wanted to follow up was the mention of your perception of valuation and options that you may have on enhancing that. Right now -- I mean, you talked about buyback -- share buybacks or dividends potential, but right now you have got a CapEx program and you're not sitting on a bunch of cash to do anything. Would you have to -- to buy back stock would you borrow or would you have to make a decision to spend less capital? I am not saying that you would do that right away, but --.

As I see it, John, your question would actually ask me to speculate on what the possibilities are. Frankly, what I think is that, you are right, there are a lot of possibilities here. We could, if we made a decision to reduce CapEx, we could borrow for a buyback. We could do any number of things. But the real choice is to see what is the best thing for our shareholders.

The basic point that I think we were really making at the start is that our balance sheet is relatively underleveraged. And we think that is a very good thing, because it provides a lot of options for our shareholders.

So you would contemplate borrowing -- well, anyway, you answered the question. Let me move on. Back to -- and I can talk to Drickamer off-line on this, but on horsepower additions and going back to cut this a different way, can you give me a sense of how much horsepower on average you will have working in 2012 versus 2011 that is -- is it a 10% increase, a 20% increase? You have given us the number, but what -- on average how much will you have working?

John, I am not sure we have an answer or have a prepared thing. We can have a look at that and see if Mike can get you an answer that satisfies that.

I am just trying to think of what you have at 20% -- a 20% increase in -- revenue generating horsepower increase in 2012 over 2011, what is the average, because I think when we look at it and we try and dial all this in the average working horsepower is going to help us understand, okay, what if there is -- you will have 20% more horsepower working in 2012. Revenue therefore should increase by 20% all else being equal or not equal.

As Doug indicated, we don't have those numbers here now.

I understand.

(multiple speakers) about it that way, but I believe the average horsepower working in 2012, if things happen as we've discussed, would be more than 20% higher.

Fair enough.

Maybe (multiple speakers). Let us think about that more.

And then just -- I guess, maybe this is a similar question too, but I think you have got -- just the math -- 140 rigs right now working that are not on contract, and about 100 rigs in dry gas basins that are working. As we transition from oil -- from gas plays to oil plays -- you know, it is not going to be seamless. Some rigs are going to be let down and others are going to be picked up, and some are going to move. And it has happened pretty dynamically in the last month or so.

Are there rigs that are actually -- I would imagine if you're making a decision, let's say, to move out of the Haynesville, some -- Chesapeake might say -- okay, we're going to move this rig, but we are not going to take this rig with us. Have you seen a decline in day rates, or are people negotiating better rates in some rigs versus moving them, or is it really just we are going to drop them here and move them somewhere else? Does that make sense?

I think the question is in a marketplace that is dynamic do customers approach you with all kinds of possibilities? Yes. Have we seen a change -- a negative change in pricing in the rig market? No.

So the answer is pricing is steady with an upward bias. I think Doug said that, I think. And so we're not seeing anything like that. At the same time, obviously, customers are more anxious to pursue their oil and liquids-rich plays than they are to pursue their gas -- dry gas plays right this minute, which you know, and is obvious to everyone on the call.

So all the dynamics are at work, but I think our customers realize that there is such a strong demand and backlog of demand for oil capable -- for rigs capable of drilling for oil and liquids that in effect as rigs are released they migrate over, and that is the real point that we tried to make in our presentation.

Okay, thanks guys. That is all I had.

(Operator Instructions). Waqar Syed.

My first question is that -- just going back to John Daniel's question that some of the E&P companies are saying that now they're seeing more pressure pumping companies and maybe drilling contractors bidding for contracts. Now as a service company, are you seeing more opportunities to bid to E&P companies as well in the plays?

I guess, if the question, Waqar, is that is our customer base expanding, the answer to that question is yes. I am not sure what -- we think that as our Company has been transformed there are customers that are now becoming -- who become customers who were customers a couple of years ago.

One of the other issues that we had seen in the pressure pumping business over the last couple of years, because of the size of these crews has got so big, you have had a very high concentration of your horsepower with a limited number of customers. So as new equipment comes into the market it does allow you to expand your customer base.

So I would say the answer to that is, yes, definitely we are trying to expand the number of people that we bid to. I think that is just a natural progression of trying to expand your customer base.

And, also, it feels like as we look through the data that the number of just the E&P companies are expanding as well, with new entrants on the E&P side coming in as well either from privates or private equity. Is that what you are observing as well?

Yes, I think that's correct.

That is one. Secondly, in terms of your -- the high spec rigs that you have, is there any new changes in design that you're implementing for the new rigs that you're going to be adding in 2012?

Yes, there is, but I would be hesitant to go much beyond that in terms of your answer. We are always looking at new and more innovative ways of improving the efficiency of rigs, both in moving them quickly. Virtually every year we introduce new little bits of technology to continuously try to improve the efficiencies of these rigs. And, yes, we are in the middle of some pretty dramatic changes in our APEX rigs.

And these new rigs, are they more toward the skid-mounted type or they are going to be more just the normal moving from one location to another?

I think you are seeing more and more people certainly interested in not only the walking type rigs, but a combination of the benefits that you get from a very fast-moving rig to a -- how do you skid them and how do you get them to drill two and three well pads very efficiently.

All right, that is all I have. Thank you very much.

Ladies and gentlemen, that concludes our questions that have been answered. I will now turn over to Mark Siegel for closing.

I would like to thank all of the participants for their joining us today on this conference call. I look forward to our next call as we report first-quarter. Thanks, everybody.

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