Patterson-UTI Energy, Inc. (PTEN) Q4 2014 Earnings Report, Transcript and Summary

James Michael Drickamer - Director of Investor Relations Mark S. Siegel - Chairman and Member of Executive Committee William Andrew Hendricks - Chief Executive Officer and President John E. Vollmer - Chief Financial Officer, Principal Accounting Officer, Senior Vice President of Corporate Development and Treasurer

Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division B. Chase Mulvehill - SunTrust Robinson Humphrey, Inc., Research Division John M. Daniel - Simmons & Company International, Research Division David Wilson - Scotia Howard Weil, Research Division Jeffrey Spittel - Clarkson Capital Markets, Research Division Brad Handler - Jefferies LLC, Research Division J. Marshall Adkins - Raymond James & Associates, Inc., Research Division Kurt Hallead - RBC Capital Markets, LLC, Research Division Scott Gruber - Citigroup Inc, Research Division David A. Wishnow - GMP Securities L.P., Research Division Waqar Syed - Goldman Sachs Group Inc., Research Division Robin Ernest Shoemaker - KeyBanc Capital Markets Inc., Research Division James Knowlton Wicklund - Crédit Suisse AG, Research Division

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2014 Patterson-UTI Energy, Inc. Earnings Conference Call. My name is Denise, and I'll be the operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now turn the conference over to Mr. Mike Drickamer, Director, Investor Relations. Please proceed, sir.

Thank you, Denise. Good morning. On behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the 3 and 12 months ended December 31, 2014. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and John Vollmer, Chief Financial Officer. Again, just a quick reminder that statements made in this conference call that state the company's or management's plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties, as disclosed in the company's annual report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the company's actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company's press release issued prior to this conference call. And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Mike. Good morning, and welcome to Patterson-UTI's conference call for the fourth quarter of 2014. 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 December 31, 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's comments, I will provide some closing remarks before turning the call over for questions. Turning now to the fourth quarter. As set forth in our earnings press release issued this morning, we reported net income of $57.6 million, or $0.39 per share. Earnings were impacted by both a noncash impairment charge to our E&P business of $16.8 million and an increased corporate tax rate associated with the December extension of bonus depreciation provisions for all of 2014. This impairment charge, along with the increase in our effective tax rate, reduced the company's net income per share for the fourth quarter by $0.14. Before talking about current market conditions, I would like to spend a couple of moments on the nonoperating items that affected fourth quarter earnings. First, with respect to the noncash impairment charge, we assess the carrying value of our E&P properties on a quarterly basis. With a sharp drop in oil prices during the fourth quarter, we reduced the carrying value of certain E&P properties on our balance sheet by $16.8 million. Second, also affecting fourth quarter earnings was an increase in our effective tax rate to 41.7% from an average rate of 32.4% for the first 3 quarters of the year, which brought our effective tax rate for the full year to 36.0% but also allowed us to file for a cash refund. By way of background, on December 19, Congress approved the Tax Increase Protection Act of 2014, which extended through the end of 2014 various federal income tax provisions that expired at the end of 2013, including bonus depreciation. By utilizing bonus depreciation for 2014, certain tax credits that reduced our effective tax rate earlier in the year will not be available to us, thereby increasing our effective tax rate for the year. However, by taking advantage of the bonus depreciation provision within the new -- within this new law, our cash taxes for 2014 are greatly reduced. In that regard, shortly after year end, the company filed for an $82 million refund of federal taxes paid during 2014. Turning to our market commentary. Things move quickly in the oilfield, and our outlook has changed significantly since our last earnings call. Putting this in perspective, WTI closed above $82 on the day of our last conference call. What was then a concern about a little bit of oil price softness has turned into a full-fledged downturn with crude oil prices below $50. Market conditions remain very dynamic and are changing quickly. The magnitude as well as the duration of this downturn are not yet known, but suffice it to say that based on current market conditions, 2015 will be a challenging year for the industry. As the saying goes, this isn't our first rodeo. While downturns do not repeat, they do have similarities. Therefore, the playbook is relatively simple: Scale down the company as quickly as possible to align with the lower levels of drilling activity. While simple in concept, the key is executing this plan effectively and efficiently. Due to market conditions, we unfortunately had to begin reducing the size of our business during the fourth quarter in the anticipation of the downturn. We have already taken significant steps to align our cost structure and capital expenditure plans with the current market. We will continue to evaluate our cost structure and capital expenditure plans to make sure we are well positioned to not only weather this downturn but also take full advantage of any opportunities that may arise. With that, I will now turn the call over to Andy.

Thanks, Mark. Beginning with drilling, the rig count during the fourth quarter was relatively steady through November, as oil prices remained above $70. The pace at which we idled rigs was largely offset by the effect of delivering 6 newbuild APEX rigs during the quarter. As a result, our average rig count during the fourth quarter remained relatively flat with the third quarter. The rigs that were released during the fourth quarter were primarily our non-APEX electric rigs and our mechanical rigs. With the delivery of the newbuilds, our APEX rig count rose throughout the quarter, and we again achieved 98% utilization of our high-spec APEX rigs during the quarter. The delivery of newbuild APEX rigs contributed to a $430 sequential increase in average rig revenue per day and a $270 increase in average rig margin per day. Beginning late in the fourth quarter and thus far in the first quarter, the downturn in the rig count has accelerated, and most E&P companies have been indifferent to the types of rigs that are being released. With oil prices below $50, our customers have reacted quickly, with large reductions in their capital spending plans, and more recently, they appear to be cutting rigs based on the rigs with the lowest financial commitment. Accordingly, since the peak in our rig count in October, our U.S. rig count has fallen 17%. As Mark mentioned, the playbook for this point of the cycle is to reduce cost for the lower level of drilling activity and to scale to the amount of work available. In anticipation of the downturn in our rig count, we began reducing our cost structure during the fourth quarter. At this time, we have already taken significant steps, as we have reduced our drilling headcount at a rate slightly higher than the reduction in our rig count. While these reductions are an unfortunate part of scaling down, we have approached this necessary step by working to retain our most experienced and best-performing personnel. At December 31, 2014, we had term contracts for drilling rigs providing for approximately $1.5 billion of future dayrate drilling revenue. In January, we stacked 4 rigs under early termination with payments around $5 million total. Based on contracts currently in place, we expect to have an average of 138 rigs operating under term contracts during the first quarter and an average of 104 rigs operating under term contracts during 2015. Further to this, we have received indications of customers' intent to early terminate a number of term contracts. We therefore expect to receive some early termination payments, and the projected average number of rigs to be under term contract in the first quarter and in 2015 will likely decline. The amount of early termination payments to be received and the magnitude of the decline in the number of rigs under term contract is uncertain at this time, but based on current discussions with customers, it could be around 20 rigs and around $40 million in the first half of 2015. This is the visibility that we have today. Focusing on the first quarter, including allowing for potential early terminations, we expect our average rig count in the U.S. will be around 165 rigs and our rig count in Canada will average 8 rigs. Excluding the benefit of any early termination revenue, average rig revenue per day and rig margin per day are expected to be relatively flat with the fourth quarter. While we acknowledge spot day rates are under pressure, our exposure to spot rates is mitigated by the relatively small proportion of our active rigs that are expected to be in the spot market. Additionally, we expect to benefit in the first quarter from a more favorable rig mix, with a larger proportion of APEX rigs working. Looking forward, during this downturn, we expect that our term contracts, our high-spec APEX rigs with quality operations and our focus on horizontal drilling will support our rig count. However, without a meaningful change in commodity prices, the industry rig count will continue to lower. We do, however, expect Patterson-UTI will outperform the industry average. In 2014, before the down cycle began, we were ramping our drilling manufacturing program to a rate of 8 rigs per quarter. We now expect to build a total of 16 new APEX rigs during 2015, all of which are under contract. Additionally, while we are not prepared to speak in detail about the second quarter, please keep in mind that with the spring breakup in Canada, we tend to average 1 to 2 active rigs during the second quarter in Canada. Turning now to pressure pumping. With the lag between drilling and completing wells, the downturn in the rig count late in the fourth quarter did not impact our pressure pumping business during the quarter. We generated record quarterly revenues of $398 million. Gross margin as a percentage of revenues improved to 21.1%, supporting sequential EBITDA growth of $16 million to an EBITDA of $78.8 million. Q4 was a good quarter for our pressure pumping business. The pressure pumping revenue growth was driven by the growth in the size of our pressure pumping fleet. For the fourth quarter, we recognized the benefit of the acquisition that we closed in October and the new spread added to our fleet early in the quarter. We also started to see net pricing improvement in the fourth quarter. But we are now beginning to see an impact to our pressure pumping activity, along with the drop in the drilling activity. For that reason, we decided not to activate a new spread that was recently delivered and scheduled to be put into the field during the first quarter. Our remaining spread on order is already under contract and is expected to be activated in the Northeast in the second quarter. This spread has technical aspects, including cold weather, high horsepower, Tier 4 engines to operate in environmentally-sensitive areas and therefore cannot be replaced by existing equipment. Moving forward, we will stay close to our customers and continue to focus on the things that we have the ability to control. Based on discussions with our customers, we currently forecast first quarter pressure pumping revenues to decrease approximately 25% sequentially, due primarily to lower utilization and also pricing. We will stack spreads to the extent that work at the acceptable pricing is not available. We are working with our suppliers to reduce our operating costs, including cost of materials and spares. However, even with these expected cost reductions, for the first quarter, we're expecting less efficiency based on lower utilization and pricing pressure. As such, gross margin as a percentage of pressure pumping revenues is expected to be approximately 15%. As Q4 margins in the up cycle did not return to peak levels, there is less room to adjust pricing going into this down cycle. Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple of corporate financial matters. Our total CapEx for 2015 is projected to be $750 million, down 29% from 2014. This breaks down to $525 million for drilling, $200 million for pressure pumping and $25 million for our E&P and other. This total also includes a $225 million of carryover from 2014. Depreciation expense during the first quarter is expected to be $172 million. SG&A during the first quarter is expected to be $20 million. We are currently projecting our effective tax rate to be approximately 36% in 2015. With that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. As mentioned, we have weathered downturns before. We've been in this business for a long time, and personally, I've been through more of these downturns than I would like to admit. While downturns present near-term challenges, they also present long-term opportunities. We have historically seized upon these opportunities to strengthen and grow our company. While reductions in headcount are something that we -- none of us enjoy, we appreciate the efforts of hardworking men and women who make up this company. With that, I am pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.10 per share to be paid on March 25, 2015, to holders of record as of March 11, 2015. Operator, we'd now like to open the call to questions.

[Operator Instructions] Our first question comes from Byron Pope with Tudor, Pickering, Holt. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: For the pressure pumping side of the business, just thinking about your Q1 guidance revenue and gross margin guidance, I think, if the math gets me right, call it 40% decremental margins. And so one of the things I'm trying to think through in terms of this downturn is how to better think about the decrementals for the year. I would assume that as some of your spreads have come off that the labor element of that can come off. It's -- maybe the decrementals, as we progress through 2015, might not be as harsh as what they might be in Q1. Is that a reasonable way to think about it?

Right now, there's a lot of moving pieces, and we are expecting to see lower utilization. Theres' a chance that we could see having to stack some full spec -- frac spreads when we do that. Of course, the labor component of that comes off. We were relatively strong in January just because of the lag behind drilling with regards to completion, but we do expect to see this sequential decreases that we've given you today. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then just on the contract drilling side of the business, I think you touched on this in your prepared remarks. But as we get deeper into the year, this notion of the favorable fleet mix, if, let's say, some more of our mechanical rigs and non-APEX electric rigs get released more so than your APEX rigs, there is no reason why that favorable fleet mix wouldn't continue to manifest, realizing that spot market day rates are headed lower? Is that fair?

Yes, that's fair. And we concur that the spot market rates are heading lower. Just like to remind everybody that with our APEX, we have a very small percentage of APEX that are working on the spot market.

Our next question comes from Chase Mulvehill with SunTrust.

A couple of questions. I guess the first one, just kind of a follow-up to Byron's question on pressure pumping. So if we think about just the absolute gross profit margins as we roll forward to 2Q, you're 15% in the first quarter, do you think that a good starting point would be 10%, or do we kind of get down into the single digits for gross profit margin there?

That's a great question. I'm just going to start off by saying, in the prepared remarks, we've really tried to give you as much visibility as we have of the business, especially with what rig count is doing and things like that. And right now in pressure pumping, this is really the most visibility that we have.

Okay, all righty.

Chase, I think, putting it slightly differently, we just don't have a good enough crystal ball to see into second quarter and to give you or any of the others on the call a very good judgment about second quarter or beyond, and frankly, that was what we were trying to indicate by saying how rapidly changing dynamic the market is. So it's not that we're trying to hold back from you. It's that we frankly don't want to get ahead of our skews.

Right, okay. I mean, how are pricing negotiations going right now in the pressure pumping side? I mean -- I know utilization is going to be a big driver of margins, but how are pricing discussions going? I mean, how much do you think that pricing could be down kind of peak -- this recent peak to trough?

Well, you're hearing a lot of commentary out there, especially over the last few weeks of where E&Ps want to get to in terms of their price reductions, but really this isn't about price reduction. It's just about getting their total costs down. And while there are some discussions around pricing, there is a lot of discussion around how do we just get cost out of the system. Are certain operators willing to use a different sand, less chemicals, maybe they're pumping smaller stages for a period just to try to get their total costs down. We only started getting that price increase in 2014 right at the end in Q4. So we just don't have a lot of room in -- to move in terms of pricing and margin in pressure pumping. But we are focused on getting the total cost down for the customers.

Okay. And how much of your sand is -- is sand pumped under fixed volume and pricing contracts, and then, what are you seeing for the spot for sand pricing? How much is that down already?

We're still in discussions with our suppliers. I think it's safe to say that -- and you heard some commentary from the sand companies early in January that they haven't -- hadn't really, at that time, really felt the full magnitude of what this down cycle could look like, and we're still in discussions with those suppliers, so rather not call out what those deltas might look like today.

Our next question comes from John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Andy, I guess, if you look across the pressure pumping business, what percent of the fleet would you describe as being fully dedicated, if you will, to the customer this year? What percent would be pursuing jobs in the spot market, and what percent have you idled? And how do you see that sort of flowing through in the next couple of quarters?

Well, as we started 2015, we were exiting a strong quarter for pressure pumping. Really proud of all the efforts of all our people in that business there as they finished up 2014. Majority of our fleets are working for dedicated customers. So we're in good shape there with a lot of relationships and the types of contracts that we have in place. We do have some customers that might make up where you have 1 fleet working for 2 or 3 different customers, but the majority of our spreads were all focused on customers. In fact, several spreads might be working for a customer. And so from that standpoint, we find ourselves in pretty good shape entering 2015 as a down cycle. Things are going to play out with utilization, with some pricing challenges for some of these customers. Some customers are laying down rigs, as you can see, just by looking at the total rig count numbers, and so this is going to affect utilization. We may find ourselves having to stack some fleets, if we can't get the type of margin from these fleets that we'd like to see. This -- the downturn in 2015 is going to be a high-magnitude downturn, like some of the previous ones, 2009, 2002, 1998. So we're just trying to do everything we can to prepare for this. John M. Daniel - Simmons & Company International, Research Division: Okay. So you haven't stacked any fleet yet or have you?

We're -- everything is still dynamic at this point. We'll have to just give you an update on the next call.

We have one fleet where we took delivery, as we said in the script, of a fleet that we didn't activate. So in some sense, John, there is one stacked, but that's not -- I'm just trying to clarify by giving that answer. That's not... John M. Daniel - Simmons & Company International, Research Division: Okay. That's fine, Mark. Just a couple of quick housekeeping, and I'll turn it back over to folks. But can you just update us, one, where the current horsepower is today, frac horsepower, what remains on order for '15, and have any deliveries been pushed into 2016?

Well, if you look at our last investor presentation, you see that about 2/3 of our horsepower is in Texas and 1/3 is up in the Northeast between the Marcellus and Utica, and that relative percentage is still the same today.

Yes. John, one frac fleet on order coming in the second quarter, I think we've called that out in the prepared remarks and that's it. John M. Daniel - Simmons & Company International, Research Division: Okay. All right, cool. And then the last one, just to follow up to Chase's comment on the sand contract. This is, I guess, for you. You can speak to the industry and if you don't want to answer, this is specific to Patterson. But I mean, if you guys can't amend the contract, your take-or-pay contract, do the sand companies recognize that puts you guys at a competitive disadvantage when bidding for work, are they included in on this yet?

We're in discussions with the suppliers. Also, I'd like to mention that with take-or-pay contracts, your take is around certain volumes, and today, we are not concerned about those volumes.

Our next question comes from Dave Wilson with Howard Weil.

Your rig count in the gassy areas, Appalachia and East Texas, have held up relative to the peaks in 2014. And I know so far [indiscernible] in rig count has been indiscriminate, as you mentioned in your prepared comments. But when it comes to the type of rig and regional focus from here, do you think there is a possibility that we see similar declines in the gassy areas, or do you think those areas continue to hold up?

Well, certainly, what we see is these are different markets. The rigs that we have drilling in the Marcellus, those are holding up better than the rigs that are drilling in the oil plays. Marcellus gas issue is really related to take away up there in the Marcellus, and there is potentially a light at the end of the tunnel towards end of 2015, early '16 with pipeline capacity. And so I think different operators are taking different approaches up there. But as you stated, we've seen the Northeast hold up better than the oily plays in the U.S. so far.

And just kind of a follow-up on that one. Are any of the 20 or so that you mentioned, early terminations, are any of those from that area or are they still in the other regions?

Yes, we just -- we're not calling out the regions right now. This is really dynamic, and that's why I say it's around 20 rigs and around $40 million, and things could shift as we go through these discussions. This is really indications from customers and not active discussions.

Our next question comes from Jeff Spittel with Clarkson Capital Markets.

Maybe if we can, rather than ask, you get the crystal ball out, if we can assess the rigs that have been laid down already, if you could give us a general sense. And I think we all agree that there is going to be a favorable mix shift for you of what percentage of the rigs that have been laid down already are APEX versus SCRs or mechanical.

Well, in Q4, as the rig count started to come down, these were thoughtful processes around dropping smaller rigs, vertical rigs, things like that. And then as we moved in towards the end of December, as oil prices continued down at certainly beginning of January, the customers just became more indifferent. This became more of a math problem for operators, as they're trying to release rigs and get everything within their budgets. And so we've certainly been working with the customers, having a lot of discussions with customers. When it comes to the early terms that we've discussed, when customers are making these decisions, they're looking at which rigs may have the shortest term. So when you're looking at, for instance, the dollars of these early terminations, maybe they're not real big, but it's because these contracts are approaching the end of the terminations as well. We're also going to be putting out 16 new APEX rigs. That's still our plan. These rigs are under contract in 2015, and so that's going to help our rig count as well.

I appreciate that. And maybe in terms of -- this is a tough one to answer, I know, but general sense that you have for when maybe the operators are a little less indiscriminate about which rigs they're letting go and the math problem you referenced, is it really a matter of we have to see the rig count bottom and it's not going to happen until well later in the year until you can think about that?

Yes, the rig count is going to continue to come down. And I think for the E&P, that's really about where do oil prices stabilize and what does that mean for their budgets.

Our next question comes from Brad Handler with Jefferies.

I guess I -- a couple of things, and if I missed some things in the comments, please forgive me. Are you at all comfortable -- appreciating the lack of visibility, but are you at all comfortable saying our best guess -- our average rig count in Q1 is x?

Yes, so we called that out. We said we expect that our average rig count in the U.S. will be around 165 rigs in the first quarter. [indiscernible] average 8 rigs.

Okay. Sorry, I must have missed that. That best guess includes the after early termination impact?

It includes the potential for early terminations. Like I said, the early terminations outside of the 4 that we've already stacked on early termination, the -- around 20 rigs that I mentioned are indications from customers, but we have included some of that potential to get to that average of 165.

To get to that 165, okay. And I guess a pressure pumping question, please. So you all -- and again, just please obviously correct me if I'm making mistakes. I was -- we were looking at the addition of 115,000 horsepower at one point in the first half of '15, which included a couple of specific fleets, like you've discussed, and then, I think there was an element of you needed it for other fleets. Am I right in those numbers? And if so, can you address the balance that was not fleet-specific? Are you still taking in that horsepower? Or is it -- are you expecting to activate it or whatever?

Yes. So today, we have 955,000 frac horsepower. We still have 50,000 horsepower to come. What we said was, though, that we had received a spread early in Q1 that we decided not to activate, and we stacked that one. The other 50,000 remaining horsepower that's coming, we've said that's going to the Northeast, and that's some specialty equipment that's high-horsepower, cold-weather rated Tier 4 engines. And so that'll continue to work.

So in your first quarter estimate -- am I still with you?

Yes.

Right. i mean, your first quarter comments about the pumping revenue being down 25%, I think -- again, please correct me, but that's on a -- is that like-for-like, or is that inclusive of the additional horsepower that we're talking about?

That'll be like-for-like, because that additional horsepower won't arrive until the second quarter.

Yes, I suppose that's true. But if you're 955,000 today, what is your average -- what was the average horsepower in the fourth quarter?

It would have been about 40,000 horsepower less, but that new horsepower was not activated. So it's like-for-like.

Right, okay. That will help me sort through things. I appreciate that. And then I guess...

Remember, in Q4, we completed an acquisition. We increased our horsepower in Q4. We -- another spread arrived at the beginning of Q1, but we haven't activated that one. And then the next spread arrives early Q2.

Our next question comes from Marshall Adkins with Raymond James. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: I appreciate the color on next quarter. I'm going to ask you to speculate on a couple of bigger picture items. First of all, you've substantially upgraded your fleet over the last few years, and that leads me to believe -- let's just say the overall rig count is down 50% peak-to-trough, just to pick a number. I would guess that you're going to be -- you're going to outperform that. Maybe you're only down 40% or 45%. Is that -- am I thinking about it the right way, or do you think you're going to be down equal to everyone else?

I think you're thinking about it the correct way, Marshall. I don't think we have as much clarity as we would like to about how large that might be. So yes, we think we'll outperform, but trying to figure out the magnitude of both the decline and -- the outperformance is pretty challenging. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Yes, sure. [indiscernible] I'm just thinking directionally, you should outperform.

I believe that's correct. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Okay. Second kind of big picture question. It seems from your commentary that the land drilling side is going to hold up better than pressure pumping over the next 2 quarters. But I would guess, in the back half of the year, that reverses, just given attrition overall in the industry and given the fact that we didn't see a lot of pricing that back half of the year, pressure pumping outperforms rigs. Does that makes sense?

I guess a definite maybe, Marshall. The challenge right this minute is to try to understand the interplay of a huge number of facts that are all kind of challenging. I mean, for example, up in the Marcellus, where we have a substantial amount of pressure pumping assets, you've got new pipelines being constructed and takeaway theoretically improving substantially in the back half of the year. That obviously is a great positive. Tell me what else happens in terms of oil prices, and I can speculate with you. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Well, I'm just thinking more drilling versus pressure pumping. I mean, obviously your drilling is under contract and that holds up near term. But pressure pumping seems to me like it would come back stronger in the back half exclusive...

I don't think we've got that visibility, Marshall, that -- maybe -- I'd love to have it, but -- I'd love to offer it if I had it, but I don't seem to think I've got any of it. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: All right. One just last quick one. We're hearing some rumors of a few big operators threatening to cancel contracts and pushing for cash breakeven costs on the rigs. Are you all seeing any of that, or is that just kind of rumor at this stage?

There is a lot of E&Ps that are really in a position where they need to get their costs down. So there is a lot of discussion, but I will say that we continue to work within the framework of our contracts.

Our next question comes from Kurt Hallead with RBC Capital Markets.

I guess I want to kind of follow on a little bit to more Marshall's line of questioning on the frac front and you give very specific guidance or a few points at least on the first quarter and obviously want to sidestep what the year might look like, and you focus on everything you can control. So within the context of everything that you can control and the context of how you might see the market evolving for the frac business, do you think you'll be able to still generate positive operating income in your frac business in 2015, as we stand right now, knowing that as soon as we got off the phone, that view may change?

With your qualifiers and as we stand right now, we see that we'll still be positive in pressure pumping. One of the things that we did mention is we are willing to stack spreads in this particular down cycle if we can't get acceptable pricing.

Kurt, I don't -- I'm not looking at the last financials for every downturn, but I don't think we've gone below 10% in terms of margins in any quarter. So the historical pattern would suggest that we are going to be able to do what you said but again subject to a lot of questions.

Yes, sure. And then, [indiscernible] again, trying to calibrate our own views with maybe how you see the market evolving and the decline in pressure pumping sequentially from fourth quarter to first quarter, mid-20%. I don't know, based on how we're looking at the world, the second quarter probably is going to look pretty similar to that. Is -- are you guys a little bit more optimistic than I am on that progression, generally speaking? You don't have to get into specifics, but generally speaking.

Generally speaking, we are seeing this big downturn with the 25% sequential drop in revenue for the first quarter. It really will depend on how we exit the first quarter in terms of discussions with customers. It will depend on what oil prices are doing at the end of the first quarter too. If that market stabilizes, maybe it works out a little bit better, but I think there is still a lot of moving pieces. It's still dynamic right now.

Okay. And then just one last one. So we became aware of a situation in the last 24 hours where a relatively small E&P company was operating 5 land rigs, 1 of which is yours, indicated that they're getting dayrates now in the $16,000 to $18,000 a day range for rigs that had been priced at $26,000 to $28,000 a day. I'm going to assume that the larger or more established drilling contractors have a lot more discipline than to effectively almost cut their price points in half for a relatively small operator. Can you give me some perspectives on that dynamic?

Yes, let me give you a little bit of color of what we're seeing right now. And we certainly acknowledge that the leading-edge pricing, especially on the spot market, is definitely coming down, and it's coming down relatively fast. We certainly aren't going to talk about specific customers or specific rig contracts. I would like to mention, like I said before, with our rigs and our contracts and the term contracts, we continue to work within the framework of the contract. And with the APEX rigs, only a small percentage of those rigs are on the spot market today.

But would you say spot market rates are under -- I mean, there is leading edge and then there is this desperation, right? And the established players, in my mind, over time don't have to act in desperation. And you've indicated that if you weren't going get a margin for a frac fleet, you're going to stack it. I'm going to assume you're going to take the same approach with the little land rig. If you -- I can't imagine that a Patterson is going to price a rig at $16,000 a day. Am I missing something?

I would concur with your premise by saying you've seen rigs come down. You know that we are going to stay focused on margins through this down cycle. And if it means we have to stack a rig or stack a frac spread, we're going to do our best to focus on the margins.

Our next question comes from Scott Gruber with Citigroup.

Regarding your deferred tax liability, can you provide some color on how that comes due as your newbuild program winds down?

John?

You'd have to tell us what the facts are going to be. It's a matter of how much CapEx you have. So as you build more rigs, you're going to have greater depreciation amounts, which is going to reduce your cash taxes. Bonus depreciation is another factor that's been talked about in the press release, in the conference call. Will we have bonus depreciation for 2015? We don't know. Today, we don't. So predicting the exact movement of that deferred tax liability is not easily done. However, year-to-year, it traditionally has not had major movements, and well that's due to what tax loss are for '15 and...

Well, assuming no bonus depreciation in '15 and given the reduced newbuild program and assuming you're conservatively down to maintenance level of CapEx next year, no newbuilds, where do you think the deferred tax liability line goes in '15 and '16?

Based on the CapEx that's been talked about here, my take is we'll get somewhere about $82 million back in our refund shortly. And as the year progresses, we would then pay a little bit of taxes if there is no bonus depreciation for '15, and we would give back about $50 million of that.

Got it. And switching gears to a higher-level question, you guys have been out in the market, hoovering up some pumping assets last year. As you survey the private pumpers, how long do you think they can defer maintenance, cannibalize idle equipment and remain competitive before they simply have to wave the white flag? Is that something that can last for 12 months, 24 months? I guess the broader question is how long before the equipment consumption on the pumping side drives consolidation in the industry?

Really hard to give a good estimate about that, because obviously the benefit for private companies is they're private, so you don't get a chance to see their balance sheets and know their sources of financing. So I think anybody wanting to speculate on that is about as good in a position as any other person is. We certainly are aware of that circumstance. The remarks that were prepared had a number of references to the fact that we've oftentimes emerged from downturns in better shape and as a better company. And one of the things that I think we're focused on is keeping our financial flexibility in place, so that we have those opportunities if and when they do arise.

Our next question comes from David Wishnow with GMP Securities.

I guess on the pressure pumping side, and obviously understood that no job is the same as another job, but of the roughly $1 million per job you guys earned in 4Q, what percentage of that is effectively passed through costs, whether it be sand or logistics, versus what do you guys actually charge for your pumping services, i.e., how much of the 20% -- 25% revenue decline in 1Q could potentially be recouped through lower-priced sand or loosening of the overall supply chain?

We don't go into that kind of granularity with the numbers, and jobs change from pad-to-pad. So it's -- it makes that difficult to call out. So we do have a significant amount of sand that we purchase and sell to customers along with chemicals. And that's where customers are looking to reduce their cost in '15. We can work with them, with our suppliers and on some of those points to try to get these materials' costs down.

Okay, great. And just to back up to the acquisition you guys did in 4Q, I think it was roughly 140,000 horsepower you acquired. How much of that did you guys scrap during the quarter? How much of it wasn't really functional equipment for you guys?

It was all functional equipment. We certainly would not have acquired it if we thought we were going to scrap any of it. It was all in good shape, and we put it to work early in the fourth quarter.

Okay, great. And did that equipment have existing contracts on it?

It didn't have what I would consider contacts, but it did come with some customers, and we continue to work for those customers.

Our next question comes from Waqar Syed with Goldman Sachs.

Andy, so you have about 177 rigs working today as per your website. Could you break it us -- break it up for us, how many APEX rigs and SCR mechanical rigs comprise that?

I don't have those numbers in front of me right now. So I really can't give you that. But certainly, you guys can go to the website and figure out which ones are direct [ph] and which ones are not. Sorry about that.

All right, this is being lazy. Okay, we can do that. Secondly, in your 165 average for the quarter guidance that you've given, what is the exit rate just for the quarter that you're assuming in that?

You can model a straight line exit from where we started the quarter. And assuming that's our average, we said it's around 165. We're trying to factor in the potential for maybe some early terms, but there's just -- there's still discussions and it's still very dynamic right now.

Okay. And the final question, could you give us the progression beyond the first quarter of number of rigs that are under contract? I know you gave the number for the year, but do you have a breakdown for the quarterly progression?

No, we don't typically provide that quarterly progression. And as I mentioned, that number could potentially be affected if there is any potential early terms as well. So still dynamic as we speak.

Okay. But assuming no early termination that you have, that number that you can provide to the Street now or...

No. We said it's -- we're estimating 104 for the year.

Our next question comes from Robin Shoemaker with KeyBanc Capital Markets.

And I just wanted to mention, since nobody has, that we all remember back in 2009, Patterson went into a severe downturn with very little long-term contract coverage, and this -- going into this downturn, the situation is very different, so good job on that. I just wanted to ask basically one question. We've read from a lot of E&P companies that they had a 15-rig program in the Bakken last year and they want to get down to 9, or a 20-rig program in the Eagle Ford, they want to get down to 12 and so forth. And obviously, they don't get there right away. But correct me if I'm wrong, but with the pace of the rig count decline we're seeing, it would seem that by maybe late spring, early summer, all of these operators probably will have gotten down to the level of rigs running that they want at the latest, I would think. But do you have a view on that?

Robin, it's one of those things where we spent several days in management meetings, getting ready for both the board meeting and then a conference call, and you ask yourself the exact same questions that you're asking. And unfortunately, there's just so little clarity. That's a rational explanation for one set of activities, but -- and if oil prices recover a little bit, you could see a better outcome. If they get worse, you could see a less good outcome. I think we're just not in a position where we have enough visibility to say more than that. And it's not a lack of wanting to. It's just a lack of ability to be able to say something with some degree of confidence and accuracy.

Thanks, Robin, and thanks for calling out the fundamental change in the company since the last major down cycle. And I'd also like to go back to Waqar's question about the rig [indiscernible] we have running today. We have about 135 APEX, around 20 of our other electrics and 20 mechanical rigs.

[Operator Instructions] We have a follow-up question now from Chase Mulvehill with Suntrust.

So I guess if we turned back to pressure pumping margins and your guidance for 15% margins on average this quarter and you guys talked about January being okay, can you just shed some light on what kind of margins you had in January?

Sorry. We don't typically break it down to the month, but we have given you some quarterly numbers.

Okay. So -- I mean, I guess, you said it was pretty good. It's not that much different than fourth quarter? Is that a fair assumption?

Fourth quarter was a strong quarter for us. The rig count was already coming down as we went into the first quarter, but there is a lag between drilling and completion. So we started off strong in January, but we certainly do expect to -- for that to come down in Q1 to the levels that we've given you.

Okay. I mean, I guess just trying to get at is what is your implied March exit rate? I'm going to get you to this 2Q margin number.

Well, I think you just have to work on that in your model.

Okay. And then one other one real quick and just from a modeling standpoint, so how should we think about your average term dayrate as we think about modeling it? Is it higher than what you've guided to in first quarter, which is about flat, for your average?

Yes, it's a little bit higher, but it's probably better if you stick with the modeled numbers there. Just -- I'll double back on what we're talking about. The delivery of the new APEX has contributed to $430 sequential increase in average rig revenue per day and $270 increase in average rig margin per day, and we do have 16 more APEX that's coming out in 2015.

Okay, all right. So your average term dayrate should increase in 1Q and in 2Q, because you have all the newbuilds coming?

We have newbuilds coming. We have a few rigs that are on spot. There's still a lot of moving pieces. So we're certainly not going to try to give you a Q2 number right now.

Yes -- no, I'm just talking term dayrate.

Term could be relatively level.

Okay. So modeling flat, okay.

Our next question comes from Jim Wicklund with Crédit Suisse. James Knowlton Wicklund - Crédit Suisse AG, Research Division: [indiscernible] the wire. Guys, how many rigs do you think industry will add this year? I know we were talking about 200-plus 6 months ago. What's the number going to be this year, your opinion?

Jim, your guess is probably as good as ours is, but I guess we would -- if we're going to throw a number, it's somewhere between 100 and 120. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Okay, I appreciate you throwing that out. You note that the rigs with the lower economic commitment will be idled first. So that gives you about 140 -- 104 safe on the contract side. Your point -- we don't know how ugly it's going to get, but I would think that considering how ugly it looks in the duration so far that rigs on contract will be safe, but that may be about it. I know you guys aren't really commenting on the rest of the year, but is that a fair thought?

We think that rigs under contract are relatively safe. What we said is that our visibility in terms of early terminations in the first half of '15 we could see around 20. Those term contracts are relatively safe in that respect. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Okay. Your office in Dubai, does the current oil price and downturn hurt or help the effort and timing of international potential?

I'd say it slows it a little bit, but we're still in the early days, still setting up and registering business, bank accounts, things like that in the international efforts. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Then last thing -- and Waqar was very nice, I'll try and be nicer. In 2 of the last 3 major down cycles, you were the best-performing stock off the bottom. Any reason that shouldn't happen again this time, guys?

I hope not.

We have a follow-up question from John Daniel with Simmons & Company. John M. Daniel - Simmons & Company International, Research Division: Just some more housekeeping. Does the revenue per day guidance in Q1 include any contract termination payment?

No.

No. John M. Daniel - Simmons & Company International, Research Division: And then, are you including any rig stacking cost or severance cost in your -- if you will, your cost per day outlook in Q1?

No, that cost is really low. John M. Daniel - Simmons & Company International, Research Division: Okay. And last one, and here's where I'll probably get in trouble. But you note that you're still operating under the parameters of the contracts, and some might say that terminology sounds a bit legalistic, and while I'm not -- I don't want to be difficult, but do the parameters of the contracts allow you to lower pricing on the contracted rigs such that it's not officially an amendment, if you will?

The contracts are holding out, and that's a good news about the term contracts. And so there are discussions with customers about how to handle things in the downturn. But what you're seeing is that these contracts are holding up. If a customer wants to terminate the rig, then there's early term provisions in the contract. And each contract has a different framework, but in general, these contracts hold up.

We have no further questions. I will now turn the call back over to management for any closing remarks. Please proceed.

Thank you, everyone. Just want to appreciate everybody's participation in the call and look forward to speaking with you in April when we do our first quarter 2015 conference call. Thanks, everybody.

This concludes today's conference. You may now disconnect. Have a great day, everyone.