Patterson-UTI Energy Inc (PTEN) 2012 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Q3 2012 Patterson-UTI Energy, Inc., earnings conference call. My name is Marie, and I'll be your operator for today. At this time, all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions).

As a reminder, this call is being recorded for replay purposes. I would like to turn the call over to Mike Drickamer, Director of Investor Relations. Please proceed, sir.

Thank you, Marie. 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 three and nine months ended September 30, 2012.

Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, 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 effects 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 or 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-UTIs conference call for the third quarter of 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 September 30, and then I will turn the call over to Andy Hendricks, who will share some detailed comments on each segment's operational highlights, as well as our outlook. After Andy, I will provide some closing remarks before turning the call over for questions.

Turning now to the third quarter, as set forth in our earnings press release issued this morning, we reported net income of $50.8 million or $0.33 per share for the third quarter ended September 30, 2012, and $241 million or $1.56 for the nine months ended September 30. EBITDA was $232 million for the quarter, and $792 million for the nine months.

The financial results for the third quarter include charges that combine to negatively impact third quarter earnings by $0.06 per share. These charges include a $12.5 million impairment charge from the retirement of 36 drilling rigs and approximately 37,000 horsepower of pressure pumping equipment. Additionally, there was a $978,000 of pretax interest charges related to the refinancing of our bank credit agreement.

The refinancing of our bank agreement increased the term of the loan to five years, increased the size of our revolver by $100 million to $500 million, and lowered our interest rate by 50 basis points. We also secured a $100 million, five year term loan which we intend to draw upon in December. We ended the quarter with $83.5 million in cash.

During the quarter, we repurchased 2.4 million shares of our common stock for approximately $39 million. Since the beginning of the second quarter of this year, we have invested approximately $109 million, repurchasing a total of 7.1 million shares of our common stock or almost 5% of the outstanding shares. We have $111 million remaining under our share repurchase authorization.

While our liquidity and balance sheet have been even further enhanced, I would like to call out how much we see this quarter as a positive reflection on the investments we have made in our businesses and the transformation we have undergone. Results for the third quarter were largely in line with our expectations, despite what ended up being more challenging industry conditions than we had expected.

Despite a sharper than forecast decline in the total US and in our rig count, our APEX rigs continue to experience high levels of utilization with better than 95% average utilization during the third quarter. The APEX rigs provide a solid base for our contract drilling business, which represents about two-thirds of our total Company revenue.

The pressure pumping market continues to be over supplied and highly competitive. Some competitors are fighting to increase market share and some are struggling just to make cash flow. Despite these challenges, our pressure pumping segment generated $48.6 million of EBITDA in the third quarter. Our experienced management team, fleet of modern pressure pumping equipment and a reputation for being able to get the job done with safe and efficient operations has allowed us to achieve good margins.

I will now turn the call over to Andy.

Thanks, Mark, and good morning to everyone. I'll start this morning with some commentary on our drilling business.

As Mark mentioned, revenues from contract drilling represent approximately two-thirds of our total Company revenues. Within our land drilling, revenues decreased 3% sequentially to $447 million due to the softness in US rig demand. In the US, our average rig count decreased to 211 rigs in the third quarter, from 224 in the second quarter, while our Canadian activity increased to five rigs from less than one rig in the second quarter. The Canadian increase was less than anticipated due to the slower than expected seasonal recovery in Canada.

Our average revenue per day was better than expected, declining by only $120, while daily operating costs did not fall as much as we had expected. Our average rig margin per day fell by only $90 sequentially, which was pretty close to our expectation that daily margins would be flat. Our daily averages were affected by many different moving pieces with the largest impact being rigs on customer requested standby.

Of the average of 211 rigs in the US, approximately 10 were on standby, and standby rigs receive a discounted day rate and have lower costs than active rigs. On the other hand, daily revenue was enhanced by a higher proportion of APEX rigs and increased activity in Canada. Our average daily operating cost did not decrease as much as expected, as labor costs were higher than expected.

First, some of the higher labor cost was transitory in nature, and second, we chose not to reduce our headcount at the same rate that our rig count fell during the quarter, as we made the decision to retain skilled people from these rigs. We have invested heavily in hiring the right people and training them well, and we did not want to let these people go during what we see as a short-term soft patch in the industry.

We believe the softness in US rig demand is primarily a function of E&P companies reducing their rig counts to stay within their 2012 CapEx budgets. E&P capital spending during 2012 appears to have been front end loaded, which has required lesser activity in the back half of the year to stay within the full year budget. Currently, we do not expect drilling activity will pick up before early 2013.

We expect our total rig count for the fourth quarter will be approximately 202 rigs, including 195 rigs in the US and 7 rigs in Canada. Included in this assumption for 195 rigs in the US are the 12 rigs we currently have on standby.

During the fourth quarter, we expect total average revenue per day will decrease approximately $500, while our total average margin per day will decrease approximately $250. This decrease in average revenue per day will be driven largely by the expiration of a limited number of higher day rate long-term contracts and an increase in the number of rigs on standby. We are not seeing significant price changes in average day rates in the spot market.

On the plus side, our average revenue is being helped somewhat by an increasing share of APEX rigs out of total rigs. Costs in the fourth quarter expected to benefit from more standby days and by cost controls.

Going forward, we are optimistic on the outlook for 2013. Fundamentals for natural gas are improving as inventories have filled at a slower pace, and we are already having encouraging conversations with customers about their 2013 drilling plans for both oil and gas. And we expect an increase in rig demand during early 2013, as E&P companies increase from currently restrained activity levels once the 2013 budgets are released. Current indications suggest that many of the rigs we currently have on standby will return to work in early 2013.

In terms of our newbuild program, we completed seven new APEX rigs during the third quarter, bringing the total number of new APEX rigs delivered in 2012 through the end of the third quarter to 16. We now expect to complete seven additional rigs in the fourth quarter, bringing the total for 2012 to 23 new APEX rigs. Since our last conference call, we have signed four new contracts for new APEX rigs. As a result, 21 of the 23 new APEX rigs being built in 2012 have term contracts. We are currently in discussions for term contracts for the last two rigs.

We have deferred one additional APEX new-build into next year. Combined with the six rigs that we deferred after the first quarter, this leaves us with at least seven APEX rigs to be completed next year. As mentioned, after encouraging conversations with our customers, we are optimistic about 2013 and expect that we will end up building more than these seven during 2013. However, the ultimate number we plan to build will not be determined until we complete our budget for 2013 during the fourth quarter.

With the term contracts signed since our last conference call, including those for the new APEX rigs, our total term contract backlog as of September 30 totaled at $1.3 billion. Based on contracts currently in place, we expect to average 132 rigs under term contract in the fourth quarter, and 79 rigs during 2013.

Before I turn the discussion to pressure pumping, let me make a few comments regarding our decision to retire 36 rigs. As we have said before, retiring a rig is not something we take lightly. As part of our rig assessment, we decided that these rigs will no longer be marketed. Certain parts of these rigs have ongoing value and the parts have been transferred to inventory to support our remaining fleet.

Of the 36 rigs, all were mechanical rigs with an average drawworks rating of 770 horsepower; 34 of these rigs were located in the US and 2 were located in Canada. We now have 147 mechanical rigs in our fleet. The high-spec APEX rigs certainly demonstrated their value during the softness in the third quarter, and the portion of our mechanical rigs that are idle represent for us a low cost call option on a future increase in drilling activity.

Book values for these rigs are low, and the depreciation and operational costs associated with holding these rigs is very low. More importantly, when these rigs work, they have the ability to generate outsize margin returns because of their low carrying value.

Turning now to pressure pumping. During the third quarter the market continued to be over supplied, and we saw some customers reducing activity in order to stay within their 2012 capital budgets. Accordingly, our utilization levels were negatively impacted, which contributed to a 12% sequential decline in revenues to $182 million. Additionally, our margins declined to 29%.

During the quarter, we decided to write-off approximately 37,000 horsepower; this retired horsepower was older and smaller equipment. Taking into account the total pressure pumping horsepower that was retired in the third quarter and the total horsepower that was ordered in mid-2011 and will have been received by year end, our total fleet is expected to be approximately 750,000 horsepower at the end of 2012. Fracturing will represent approximately 663,000 of the 750,000 total horsepower.

Within the pressure pumping segment, we believe we have several competitive advantages that differentiate us from some of our competitors. In addition to our regional expertise, extensive training and experienced pressure pumping management team, we also have a fleet of modern, high-spec pressure pumping equipment. Of the approximately 663,000 fracturing horsepower we expect in our fleet by the end of 2012, the average age of this equipment will be only three years.

Going forward, we expect the pressure pumping market will remain competitive, but we are starting to see some indications that has us relatively more optimistic on the outlook. While we are not calling a bottom, we believe the rate of decline in pricing is slowing.

For the fourth quarter, based on current conversations with our customers, we expect a slight improvement in our activity levels earlier in the quarter and this will be offset by the impact of holidays later in the fourth quarter. Accordingly, pressure pumping revenues are expected to be down approximately 3% while our pressure pumping gross margin is expected to decrease approximately 100 basis points.

Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple other corporate financial matters. We currently expect SG&A to be approximately $17 million in the fourth quarter. We also expect depreciation expense in the fourth quarter of $133 million. Full year 2012 CapEx is still expected to be approximately $1 billion. Our effective tax rate for the fourth quarter is expected to be approximately 37.5%.

With that, I will now turn the call back to Mark.

Thanks, Andy. There's a quote that has been popularly attributed to Warren Buffet that goes something along the lines of, you never know who is swimming naked until the tide goes out. In a cyclical business, it's easy to point at the value your investments have created when times are good, but I tend to believe that you do not realize the true value until there is a slowdown.

We have invested in our business throughout the cycle in order to fundamentally transform our Company, and despite the slowdown in the third quarter, we've performed well. Since the beginning of 2006, we have built 107 APEX rigs. Rig demand softened during the third quarter, but nonetheless, our APEX rigs were able to achieve better than 95% utilization.

We have increased the horsepower in our pressure pumping fleet by more than 1,000% since the beginning of 2006. Despite concerns about the health of the pressure pumping industry, our pressure pumping business generated $48.6 million of EBITDA, achieving almost a 27% EBITDA margin.

Beyond investing in equipment for our two core businesses, we have also invested in our people. We continue to focus on hiring the right people, implementing new training programs and retaining the right people. While we've been making these investments, I'm proud of the fact that we have also returned capital to shareholders.

This year alone, we have repurchased $109 million worth of our stock, or approximately 5% since the beginning of the second quarter, and we still have $111 million remaining under our share repurchase authorization. This year, we will distribute approximately $120 million in dividends. Since the beginning of 2006, we have returned more than $1 billion to shareholders in share repurchases and dividends.

Going forward, we will continue to balance further APEX newbuilds with share repurchases, dividends and acquisitions in order to seek the best long-term returns for our shareholders. We remain confident in the demand for our advanced technology rigs and the returns to be achieved from these rigs. And we believe our strong financial position and balance sheet will continue to afford us the opportunity to both add new equipment and return capital to our shareholders. While we are just starting our budgeting process for 2013, we do expect that CapEx will be lower next year.

Before I conclude, let me echo a couple of positive comments that Andy made. As Andy mentioned, based on conversations with customers, we expect activity to increase in early 2013 as E&P companies get their new budgets. Long term, we see a strong national interest in using our abundant natural gas supplies and making use of our ability to produce oil domestically. We continue to shape our Company to enhance our already strong position in these two important national natural resources.

With that, I'm pleased to announce today the Company declared a quarterly cash dividend on its common stock of $0.05 per share to be paid on December 28, 2012 to holders of record as of December 14, 2012. Let me conclude by thanking the men and women of Patterson-UTI for their contributions.

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

(Operator Instructions). We have our first question, and it comes from the line of Marshall Adkins from Raymond James. Please go ahead.

Good morning, guys. Nice quote, Mark; I like the Buffet stuff.

Thank you, sir.

Help us to understand directionally where we should be thinking about day rates and really, more daily margins going forward. There's so many moving parts to that right now with new contracts coming online and -- that are higher priced, leading edge rates coming down, costs probably coming down. Give us some sense what you guys are thinking for the next quarter or two, in terms of the trend on day rates, and really, daily margins.

That's a good question. We get a lot of conversation about day rates; it's actually quite interesting. You're right when you say there are a lot of moving parts here.

As we talked about in what we see going forward for Q4, we have a mixture of some term contracts coming off. We have the mixture of some APEX rigs and different things that are moving within the numbers on the averages. But as I stated, we just don't see a lot of movement in the spot prices on a well-to-well basis, depending on the region or the basin in the US; from well-to-well, some might go up, some might go down but on average, they're just not moving a lot. So, relatively flat on the spot prices.

And on some of the new contracts that we've got, we just don't see a lot of movement on what we're doing for new APEX rigs. Mark, do you want to add to that?

No, I think that's a fair comment. The fact is, Marshall, that there's a lot of factors that were affecting both average daily revenue and average margin in the quarter. And we tried to highlight a couple of them, but there's a lot of different numbers going in a lot of different directions, frankly.

Right, so I mean -- I guess most of us are probably thinking, obviously, directionally, margins are going to head lower. Sounds like in your mind, if it does move lower it's not a lot lower, is that fair?

Yes. Well, you saw what we were talking about in our looking forward to the fourth quarter, that remarks that we've given were for relatively modest changes.

Right, right.

And we're talking about a decrease of $500 a day in total revenue and margin of $250. That's pretty modest, I think.

Yes, it is, that's why I was asking. All right.

Second one is same thing, pressure pumping, I guess I'm a little surprised. I think you mentioned 100 basis point decline in margins on the pressure pumping. We're hearing a lot of guys out there may be bidding at breakeven cost, stuff like that.

You guys have held up a lot better, and it sounds like you expect that to be going forward. Can you give me more color on that?

Yes, so that's another interesting one, as well. So our pressure pumping, we're in two regions. We're in the northeast in Appalachia, and we're in the southwest, and with our customer base, we've been steady with the customers that we have.

Our bigger challenge in Q3 was more around utilization than it was on pricing. In the April call, we said that our average pricing was coming down around 20%. I think that still holds true for our average pricing. Certainly the spot market pricing has been a lot more competitive, but we haven't had to compete so much on that spot market.

And again, Q3 for us, utilization challenge. And Q4, as we get into holiday seasons, potential weather in the Northeast, still it will be a bit of utilization challenge there, as well, similar to Q3.

All righty. Thank you, all.

Okay, thank you. Our next question comes from the line of James Crandell of Dahlman Rose. Please go ahead.

Good morning, guys.

Hey, Jim.

Andy, if I heard you right, of your new APEX rigs, you've been able to get 21 of the 23 under long-term contracts and have pushed 2 into early next year. Assuming that's right, are you ruling out bidding on shorter term work than three years with any of your APEX rigs?

And again, if I heard you right, the day rates that you've been getting recently on these term contracts are very, very similar to those of a year ago?

Yes, Jim, so just to clarify, we deferred one additional APEX into next year, so it gives us a total of seven in the newbuild program to start for next year.

With regards to the contracts on the newbuilds, I think we don't get into the details of exactly all the terms. Certainly, there's been a little bit more pressure on the nature of the term of the contract than there has been on the pricing of the contract, and pricing is holding relatively steady for the new APEX contracts.

But you're not bidding any of the new rigs on what you would call short-term work?

We're certainly not putting newbuild rigs on the spot market. The newbuild rigs are getting term contracts.

Okay, and could you -- my follow-up to that, Andy, is could you differentiate a bit on in your pressure pumping business, market conditions in the Eagle Ford, Permian and Appalachia, and maybe compare and contrast them?

Okay, yes, very different markets. You know, Appalachia, was certainly challenged with natural gas prices. We've seen that work its way up a little bit. And I think it has taken some of the pressure off Appalachia, and gives us some encouraging signs as we come out of Q3 and into Q4.

But again, we're just concerned that we're going to run into some utilization issues in Q4 with holidays, and if we get some good rains in the Northeast at the same time in the fall.

In the Southwest, we see a bit of a spending shift from Permian to Eagle Ford, but I think we're well set up in both of those markets and we have the ability to move between those two markets easily. So, I think we see continuing challenges in the markets with the oversupply, in general, across all the basins, but right now, we're just focused in Appalachia and Southwest, and our guys are doing a good job and they're holding their own in those basins.

Could you remind me, Andy, your last spread of equipment that you took delivery of? Is that working or have you held that off the market?

So, we have just under 100,000 horsepower that we have -- by the end of the year, when all the deliveries come in from last year's orders, it will be just under 100,000 horsepower that we will have taken delivery of that we have not activated. In other words, haven't spent the money to invest and crew them up, or haven't put that equipment to work.

So, that equipment is sitting nicely in West Texas; nothing's going to happen to it. We don't have any plans at this time to activate that equipment. We just have to wait and see how the market plays out.

Good. Okay, thank you.

Okay, thank you. Our next question comes from the line of Joe Hill from Tudor Pickering. Please go ahead.

Good morning.

Hi, Joe.

Guys, we've benefited from this inertial drift in term rates for, I don't know, two years plus, where you've had older contracts fall out of your term bucket at lower rates and your incremental term contracts have been at higher rates. So, it has been very supportive of your blended day rate.

It sounds like maybe we're seeing an inflection point where that effect is flipping to the negative. Am I correct in that observation?

Joe, I think that it really all depends on when the term contract was signed and for what region it was signed. And we were extremely -- we found ourselves in an extremely fortunate position in late 2009, particularly for rigs going into certain of our markets where we were very strong and people wanted specific rigs that we had. And we were very fortunate in some very advantageous contracts that were, in fact, above what was then the average price for term contracts.

Some of those are rolling off, and being reset at numbers that are more in line with current market. So, yes, you can see in our numbers, some of those, and that's why we use the word limited number of these rigs.

So, I think that you're correct, that there are some of them. To then go to the next step, and say that these particular instances give you a trend line, would be something I'd be a little uncomfortable with because I think it all depends on which rig under which circumstance.

I think that, in effect, term rig that -- term contract expires that's re-termed by the in effect customer for an additional term, we haven't seen all that much change in that marketplace, so that's why I'm being a little hesitant. We've seen some in particular instances, but not across the board.

Okay.

Andy, you want to add anything to that?

No, Mark. That -- as we said before, there's a lot of moving parts to this, as you well know, and I think Mark described that one pretty well.

Okay, and then, you guys saw, what I think, is pretty nice success in the quarter in picking up 11 more term contracts. For the fourth quarter, your guidance went from 121 to 132. To what do you attribute your success in doing that?

I guess we'd like to think that we're doing a good job for our customers, and they're satisfied with the work that we provide and the service we provide. Joe, I really can't explain it any other way than to say that I think that it reflects the customer's acceptance of the service we provide.

That's the best possible answer. And finally from me, Andy, you talked a little bit about pressure pumping maybe feeling a little bit better than it has been. Early fourth quarter activity picking up from Q3, and then we'll of course, get the seasonal fall-off.

What's driving the improvement from Q3 here? What's the change?

I think coming out of Q3, we had some -- again, in Q3, we had some spotty utilization where customers were telling us instead of fracking six days a week, we want to dial that back to five and four. And so that hit us on both the revenue and the margin in pressure pumping.

But I think that with natural gas trading in the mid- to upper-$3s, it's giving some support to some more work up in Appalachia, and we're just continuing on in the Southwest at the same time.

Okay, sounds good. I'll turn it over. Thanks.

Thank you. Our next question comes from the line of Robin Shoemaker from Citigroup. Please go ahead.

Yes, thank you, good morning. I just wanted to ask about, going back to this market for AC drive rigs, we've -- we now know there's quite a few stacked AC drive rigs in the industry, industry-wide. The figure I heard yesterday was 94, but I don't know if that's a good estimate. But it's clearly putting some downward pressure on spot rates, and there's a lot of term contracts that are coming up for expiration.

So clearly, your story is -- your experience here is definitely better, but do you foresee having to get on your expiring contracts more competitive, assuming that they're going to be put into kind of a spot market environment?

I think the first point of -- the way we would perhaps start out by thinking about it, Robin, is I'm not sure we agree with your premise that there's this huge amount of AC powered rigs that's available and, in effect, being laid down. Our figures show that the utilization of the AC rigs is something in the high 80%s, or at least mid-80%s, and therefore, we don't see numbers of the sort that you're giving us.

And certainly, we don't have those as a Company, that oversupply of rigs. And so quite frankly, we think that there's actually a sense on our customer's part, that there are not -- there certainly are rigs in the marketplace that are idle. I'm not trying to quarrel with that. But the sense that there's an overabundance of idle rigs of the highest quality is the part that I think I'm quarreling with a little bit in your question.

Overall in the industry, Mark's right. We pulled up some of the numbers, and it's in the upper 80%s on the total AC utilization. Of our APEX rigs, we're seeing 95%. So our APEX rigs are certainly very competitive in the market, and we only have one AC down right now.

Okay. Just let me ask a little kind of a parallel question to that. We hear a lot about some smaller start-up companies, private equity backed, that are introducing new AC drive rigs into the marketplace at a time when their timing of those introductions is not appropriate -- is not -- (laughter). It's not great timing. So in other words, they're kind of in between a rock and a hard place, and have to discount those rates pretty aggressively.

I'm not exactly sure exactly where they're marketing those rigs or -- but do you see that phenomenon affecting the marketplace? I guess that's my basic question.

You know, I don't really see a big effect there. If you look at what it takes to operate a fleet of AC rigs across the country, when you look at an AC rig versus another type of rig, the level of assembly, commissioning, maintenance and technical support long-term for a rig like that is at a much different level than previous classes of rigs. I think that we certainly have the infrastructure across North America to be able to handle the support for this type of fleet of rigs.

Robin, I would just add that firstly, we've seen over, at least I have, over a number of years in this industry, private equity build new rigs from time to time. Historically, and I believe it's the case again this time, it's a very limited number of rigs. It doesn't have much impact on the overall rig business and certainly not on a company of our size.

Quite frankly, the start-ups are challenged in the same way that Andy just described because they're facing the problems that we have a chance to deal with because of our size, including training, insurance, all kinds of other things that, in effect, are our advantages that they don't have.

So yes, they can come into the marketplace, they can have some impact. But also, I think our customers are rather reluctant, particularly the established customers, to want to use people who don't have much of a history.

Okay.

I'd like to just clarify one thing from the prepared remarks. I said that after the fourth quarter, our dividend distribution would be $120 million. I should have said will be $30 million during this year. That's a mistake on our part, and my apologies for it. The distribution this year would be approximately $30 million. It doesn't change any of the other numbers that I gave.

Thank you.

Okay, thank you. And our next question comes from the line of John Daniel from Simmons & Co. Please go ahead.

Hey, guys, good quarter.

Hey, John.

As you well know, a couple of your larger frac competitors were pretty aggressive with their bidding over the past two quarters, and in hindsight, it seems that they may have overdone it with the price cutting. Are you seeing any signs that they might be trying to work their pricing back higher?

You know, we're certainly encouraged by some of the things that we're hearing, but I would say to date, it's still a very competitive market out there. Certainly, we hear in the Northeast, there's in the range of 20 spreads that are still on the sidelines up there.

That's why I've really got to commend our pressure pumping teams for the work that they're doing and the good service they're providing, because they're doing a good job for the customers out there that we have and we're -- that work is still progressing. So, I would say that we haven't seen a change in the market yet, but we're certainly encouraged by some of the things we're hearing.

John, I'd just add to what Andy just said. It's kind of interesting, we started out by saying we're really proud of our Company and how we've performed in this difficult market environment. I would say that one of the things that the management team is most proud of is how well our pressure pumping business has performed in an extremely competitive market, I might even describe it as hyper competitive marketplace.

And they've done so, I think, by being able to, in effect, provide the customer with a better value equation. And the better value equation is that we don't necessarily have to charge you the cheapest price, but the overall value of what we provide is superior. And I think that's been what's seen us through this rather difficult time, and why we haven't had quite as much margin compression as some other people have.

Certainly, from our standpoint, we don't see the need to chase work on the spot market, and that's why we have the new horsepower that we have just parked and not activated.

Fair enough, okay. I know you don't want to call a bottom on margins, but given your belief that activity increases next year, do you sense that your frac margins will move higher in Q1? Assuming no major weather issues? Or is there a risk that contracted pricing rolls and kind of takes a step down from Q4?

I think we're reluctant to make those claims, John, because of the amount of equipment on the sidelines and the number of competitors who may be, in effect, inclined to do desperate things. You hear of certain competitors who are making comments about not being as price conscious and price competitive and market share driven as they were. But yet, you know that the market place has a lot of other players and you can't really predict two quarters out what those players are all going to do, so I think we're -- that's why we're cautious about those remarks.

Okay, fair enough. Last one from me. Is there any way you could frame for us the current split between your cash margins contracted versus spot, even if it's a range?

I don't think we have that information at hand.

Okay.

I'm looking at John, and I don't think we have it, John, sorry.

Okay. Thanks, guys.

Okay, thank you. And our next question comes from the line of Brad Handler from Jefferies & Co. Please go ahead.

Thanks, good morning, guys.

Hey, Brad.

Can you please split out the $12.5 million in between contract drilling and pumping?

It's approximately half and half.

Okay, thank you. So, I guess a point of clarification for me. In your guidance relative to, say, pressure pumping margins, if I take $6 million out of the expense line for the third quarter, and I get a 32% EBITDA margin in pumping, is that the reference point that you're guiding us to relative to Q4, down 100 BPS? Is that the way I should be thinking of it, or is it assuming no add back, and so I think it's closer to 29%?

The comparative number for the third quarter is 29%, going to 28% is the estimate. We're just taking pressure pumping revenue less pressure pumping direct cash costs, and we are considering G&A for that purpose.

Okay. But the important thing is the -- yes, I think I've got it. The reference point does not add back the impairment charges; you're looking at that as part of your ongoing -- that's your third quarter number, and you're working from that.

No, the --

I think we're not considering depreciation when we're giving you the margin -- we're looking at a gross profit, in effect, percentage, which is revenue for our purposes, less cash costs. We're not talking about the depreciation number in there.

Okay.

Yes, the depreciation, I think, John, correct us if I'm wrong, is in the G&A number.

Well, no, it's just the way they're broken up for the numbers he has, you have revenue, you have, in effect, cost of sales, you've got G&A and you've got depreciation.

Yes.

And we're -- purpose is 100 basis points, we're not speaking to G&A nor depreciation.

All right, I think I got it. But the point is, it's the $129 million you reported in costs.

Yes.

And that's -- so that -- revenues less that number is your margins, 29% roughly, I think, and then it's 100 basis points off that, right?

Yes, correct.

Okay, all right, that's fine. Thank you. Second question, unrelated. I guess what can you tell us about the strategy on the newbuild front in a couple of ways? Obviously, you said you've got -- I understand you've got to formalize the budget before you commit to numbers, but I guess roughly speaking, maybe you can comment about -- is there some -- is there a minimum level of activity, which is just sort of logical that means you put out an APEX rig a quarter or something more like that anyway?

And I guess I'd also appreciate if you could speak to the idea of adding walking systems onto mechanical rigs, and how you think about the opportunity set for that. That hasn't gotten any discussion on our call, but obviously, that's an option, as well, if I understand it.

Sure. Let me take the walking systems, second, and completely separate from the conversation about newbuild rigs.

Okay.

So, as respects the newbuild rigs, Brad, your first comment was absolutely correct. We typically have set our capital budget in December, and have our Board approve it at that point. We have not, obviously, done that yet and won't do that until then.

But we have obviously, these seven deferred rigs that we are carrying forward from our, in effect, 2012 approved budget. So that's in the -- in effect, been approved by our Board and there.

Sure.

What we kind of anticipate, but this, of course, is at this point, more or less kind of a swag, is that we'll build about two rigs per month in the first half of the year. And that's totally consistent with the rate of building in 2012, and so it seems like a very logical expectation for us.

Obviously, we have the ability to adjust that number upwards or downwards, depending on what we see in terms of demand. We're not going to out build the market; we're going to be cautious about that. But we're also pretty darn optimistic about our customers' interest in these new rigs and the demand for them. So, that's kind of a broad oversight, if you will, of the newbuild.

As respects the walking rigs, I have maybe two or three comments. The first is that, as you know, I'm sure, our original walking rigs are really the industry standard. We're now seeing some of our competitors really move to try to, in effect, build rigs very similar to rigs that we've been building for a number of years, where we think we have a very significant competitive advantage, in terms of a certain kind of walking rig.

Number two, we've been able to put walking rigs on others of our new AC electric rigs and adapt them so that they can have walking systems, which allow them to do all the traditional kinds of walking. I see no reason why we couldn't do that for our mechanical rigs, as well. But I would say that we're probably the contractor with the greatest ability and the greatest amount of their fleet already set up for walking, and so we're well positioned in that area already. Andy?

I understand. So the take-away is that sure, you have the option to do that, but that's not -- it's not something you necessarily feel that you need to catch up on. Right.

The opposite; we have the lead. We're certainly not playing catch up.

Yes, clearly in the walking --

On the APEX walking rigs, we have 55 currently on the market. And just to clarify what walking means, walking means on a pad that you can move in both an X and Y direction. You can move in two directions. This is not a skid; the skid just moves in one direction.

So we have 55 of the APEX walking rigs out there today. The APEX 1000 was originally built with an option for a walking package, and we recently updated an investor presentation to show that the APEX 1500, which is a bigger fast-moving rig, also now has an option for a walking package. And that option that we did for the APEX 1500 can be retrofitted to any of the SERs or mechanical rigs in the fleet, if necessary, or if required by a customer.

Understand. I feel like I might be sneaking in one more too many, but any comments on the Canadian drilling re-negotiations for the winter season? Can you comment on rates in that context?

You know, we're not seeing any change in the rates. We're just seeing a softer market up there. It was slow to come out of breakup in the summer, as everybody saw, and we're just not -- we're not forecasting the peak that we saw last year, basically.

So, a slower winter drilling season?

In general.

Okay. Thanks a lot, guys.

Okay, thank you. And our next question comes from Waqar Syed from Goldman Sachs. Please go ahead.

Thank you very much. I just want to check with you on Appalachia. You mentioned some pick-up in activity. Is that related to companies going back and competing wells that they had previously drilled, or is this some of the new wells that have been drilled where you're gaining some market share?

In Appalachia, I think what we're seeing right now has more to do with people getting comfortable with where the commodity prices are and the range they're in right now. And we see some increase in the utilization from that. We're not adding frac spreads up there; it's just that frac spreads that we have are getting a little bit busier in their scheduling and the utilization is improving.

What you're asking with regards to going back to older wells, to add fracs or add stages, where initially it might have been just the toe that was fracked, we don't see that yet, per se. So, I wouldn't say that's a driver in what's happening. I think there may be some potential in that in 2013, but it's not a driver material to the numbers that we're talking about right now in Q3 or what we see in Q4.

Okay. So in your view, as commodity prices came down, based on the rig count, what percent of your jobs were seeing like a reduced number of frac stages versus what you saw early in the year or last year?

Like I said earlier, what we saw in Q3 was really -- it looked like people were just staying very close within their budget numbers, maybe potentially a little bit constrained. And we just saw the utilization drop where not so much fracs per well, but just overall number of fracs, in general, were coming down. And the effect on us is we would frac four and five days a week instead of six or seven days a week, or from long daylight hours to reduced daylight hours.

And is there a way to quantify your utilization for the equipment that you've activated now on your -- in the pressure pumping side?

We haven't activated any new equipment.

No, in terms of what is already activated, what is today being marketed, what is the utilization level for that equipment?

It's actually a difficult number to get to, because it depends on the well types that you're fracking, the regions, the basins and things like that. We look at how the schedules are filling out, and like I said, coming out of Q3 into Q4, we're seeing the schedules fill out, but we're very cautious on utilization in Q4 because we know we'll get into seasonal aspects and also potential weather issues in the Northeast.

Okay, and then just one final question. What do you need to see to activate your non-marketed pressure pumping fleet, the new fleet that you've recently built?

In general, I think for us to activate another fleet, we would have to see some kind of contract and pricing level similar to what we're getting today, whether it's Northeast or Southwest. Because like I mentioned earlier, we just don't see a need to go chase contracts at the spot market just to put equipment to work at low margins. We're still staying very focused on the margins in that business.

Okay, thank you very much. Appreciate the color.

Okay, thank you. And our next question comes from the line of Brian Uhlmer from Global Hunter. Please go ahead.

Hey, Brian.

Hi, good morning, everybody. Good quarter.

Thank you.

I have a couple of questions following up on your swimming naked line. I'd like to address two topics in the industry, and the first one I want to talk about is shrinkage. With you guys dropping 37,000 horsepower, something along those lines, do you feel like that that's something that could happen industry-wide? And what kind of estimates do you have in the industry as to what portion of it could potentially be cut up and go away to maybe help balance out the market?

That's an interesting question. You bring up a good point. It's hard for us to say what other fleets look like. In our particular case, we had a mixture of some older equipment that we had on yards that we just didn't anticipate it going back to work in some cases, some smaller body load pumps for maybe some other types of services.

We do more than just frac; we have cementing, we have acidizing, we have nitrogen, and so we have a variety of different kinds of pumps and quantities of horsepower, per se, out there. And we just looked at some of the older, smaller equipment and decided in today's market, we just didn't see that going back to work.

Now, with your experience in the industry, do you feel like there could be -- we could start to see that potentially as we go into Q4 and '13 from some competitors?

I think it's a possibility. I think it depends on relative ages of fleets that are out there with some of the other companies, but I would say it's a possibility.

Okay. Following up on the same topic, when we talk about some of the guys at the lower ends who have private equity sponsors, and who are kind of forcing pricing down and as you say, potentially caught naked, what do we see happening with all these naked fellows moving throughout the year? Is there going to be consolidation, or do you think the private equities sponsors back them? Are there opportunities for Patterson to do some consolidation, as well?

We're always trying to find good opportunities to, in effect, acquire assets at attractive prices so that if, in fact, that does materialize, we would be very interested. Quite frankly, predicting how private equity sponsors will respond to this kind of a situation seems to me to be one of the harder, if not impossible tasks. You just don't know whether someone will say, oh, look, I think it's going to get good next week, next month, next year, whatever period of time, and decide to stay the course and to, in effect, pour more money in, or whether people will say, hey, wait, let's just take a graceful exit.

I don't know what will be the case, and Brian, as much as I would like to be able to make a good prediction on this one, my experience in doing transactions, which is pretty darn long at this point, is that they come along unexpectedly. And when they do, the thing that really marks the difference between some people and others is the ability to seize the day, and understand how to really react well to the ones that you want to react well to and understand the ones you need to pass on.

Sound good. There's been no change to your stance that you're not collecting assets just to collect them. They have to be a pretty steep discount in order to do something in that pressure pumping arena?

Yes. I give you the sort of answer that you know, which is the one that when you buys assets, you're thinking to yourself, am I creating value for the shareholders? And just to own one more of anything, a truck, a rig, a pressure pumping piece of equipment wouldn't be of value. Owning something that would -- could generate revenue and profit is what makes something valuable.

All right, thank you, sir.

Okay, thank you. And our next question comes from the line of Tom Curran from Wells Fargo. Please go ahead.

Good morning, guys.

Hi.

Returning to the line of investigation by Brad earlier on the walking rig technology, I think of your leadership there, technologically, as being inextricably linked to your long-standing leadership in Appalachia. Could you speak to where we're starting to see the incremental demand emerge, outside of Appalachia, for walking rig technology and where, ultimately, you see the most growth potential for it?

Sure. I just would like to start out by kind of making an observation, which is that the first 10 of our walking rigs were built for the Rockies in 2005, 2006. I believe that the first one that was, in effect, deployed outside of the Rockies was in the Barnett, and then the rigs actually sort of migrated. They didn't walk, I would tell you.

They migrated to Appalachia and were obviously, successful. We were actually asked to take some of the technology, which we had pioneered in the Rockies and later brought to the Barnett, to Appalachia, which was extremely successful when brought there.

And so we've been doing this, and the real point of the 2005, 2006 starting point is to say that we're into this with a lot of experience over kind of a seven -- six, seven year basis. And so that's why I gave the answer that I gave the first time to Brad, which is that we don't see ourselves as having to chase anybody in terms of leadership positions or walking positions. We think we're pretty well established in that as an industry leader.

And thank you for that clarification. It's very helpful. But from this point forward, especially given you're one of only two drillers thus far that's reported incremental newbuild contracts, and all of the ones we've heard about thus far have been for walking rigs. Where are you seeing the incremental demand now outside of Appalachia?

I'll toss this to Andy, as well, but my reaction is we're seeing demand for both walking rigs and not walking rigs, we're seeing demand in Appalachia, we're seeing demand outside of Appalachia. So it's not that it's A or B, or X or Y.

Yes, I don't want to bring it down to the basin level, but I'll say it's really kind of operator dependent in how they choose to develop their field, and if they choose to put a number of well heads together or just a few well heads together. And different operators have different strategies in different basins, but certainly, we have several different options for them.

Okay, good to hear. While I'm on Appalachia, it seems like it would be the first market to see a turn in demand in response to the sustained rebound we've had in gas prices. And again, as the leader there, I would think you guys are the best positioned to know what the operators, what it might take and therefore, when they might move. What's the latest you're hearing?

Well, we're definitely encouraged, both from the commodity prices and where they're trading today in the range, and then also with discussions with customers up in Appalachia. I think like we said, it's too early to call a bottom on things, but we are in some encouraging discussions.

Okay, thanks for squeezing me in here towards the end. I'll turn it back.

Okay, thank you. Our next question comes from the line of John Keller from Stephens Inc. Please go ahead.

Hey, guys. Thanks for squeezing me in here. Just one quick one, I think everything else has really been answered. You're obviously pretty optimistic, it sounds like, about 2013 and I think you cited discussions with customers. But is there anything beyond that that you can shed light on, as to why you have that kind of bullish stance and why you think the flip of the calendar is going to bring a brighter day, if you will?

We've really talked to you about the fact that we're very much customer-driven. And when our customers talk to us about the fact that they foresee the possibility of incremental rigs needed in a -- going forward when they talk about incremental frac work they expect to do various other things, it encourages us.

Now, there's a big difference between a contract and a conversation. Right now, we're having some contracts and some conversations. We're hopeful that more of the conversations will turn to contracts, but we're encouraged because we've had a pretty good success rate in doing that.

Fair enough. And anything -- what would be the major things, I mean, obviously, commodity prices, some -- but what do you think fails to turn those conversations into contracts?

I frankly think -- and I don't think I have any particular special insight here. I think that the E&P companies are looking at their budgets and trying to make some real hard decisions about what they think the direction of the economy is, and what the direction of the commodity prices are. And that, to me, is what I think is going on. Andy?

I think what we saw this year so far, we just saw some challenges as we moved through some commodity bumps in the road in May and June and into budget season. And it was just a more challenging environment to make some decisions on forward progress as far as drilling plans. But we're in some encouraging discussions right now.

Well, fair enough. That's it from me, guys. Let's hope you're right.

And we have another question, and it comes from the line of Jason Wangler from Wunderlich Securities. Please go ahead.

Good morning, guys. Just had a quick question as far as the 100,000 horsepower that you have kind of idled or not running, at least. Could you just give some color maybe on how much that would cost, and maybe the timing of when you could get that into service when you saw that timing be -- present itself, I guess?

You know, that's really -- there's two things. It's under 100,000 horsepower, and it's really a market condition question. And for us, the right opportunity at the right price would have to come along for us to activate that.

So, we're certainly always on the lookout for the opportunity, but as I said before, we're not chasing work at the spot price. And the only real cost for us to activate that, is just the upfront cost of bringing the people on-board.

Okay, great. I appreciate it.

We have our last question, and it comes from the line of Alan Laws from BMO Capital. Please go ahead.

Good morning, guys. Thanks for getting this last in. More of a philosophical question to finish off here. You've been putting up, what I would consider, differentiated results, especially relative to your own experience in prior cycles.

You've been balanced in return of capital and reinvestment in the fleet, you have a good balance sheet, you're recognized, really, as a preferred vendor out there. Why not use the opportunities in this interim slowdown to accelerate your new rig investment, sort of take more share, and better position yourself for the future? If the stock's already kind of discounting bad stuff so you can't hurt that much more.

(laughter). Well, I firstly want to thank you for the positive comments that were implicit in the question, and secondly, say to you that I think we're kind of doing what's gotten us to this point. We balance, as I see it, between, in effect, reinvesting in our business by increasing our rig fleet, historically increasing our frac fleet. We're not looking to do that right now, but we have done it, and at the same time, give back capital to our shareholders.

Quite frankly, when John and I were doing the kind of work that leaves behind over $1 billion returned to shareholders, we were pretty blown away by the size of that number, particularly in light of the amount of money that's been reinvested in the business. So, I kind of think we're going to keep doing what we've been doing, and I recognize your comment could be, well, you could do more of it, but frankly, what we've been doing has been working for us pretty darn well and we I think are pretty clearly going to try and stay on that path.

That's definitely fair. Every new season you seem to be putting out a better team in the field, so nice work.

Thank you. We appreciate that comment. Well, ladies and gentlemen, thank you very much for joining us. We very much appreciate everyone's participation in this call, and look forward to speaking with you at the end of the next quarter. Thank you.

Thank you, ladies and gentlemen. That concludes your conference call for this afternoon. Thank you for joining us and you may now all disconnect.