Patterson-UTI Energy, Inc. (PTEN) Q4 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Q4 2013 Patterson-UTI Energy, Inc. Earnings Conference Call. My name is Michelle, and I will be your operator for today. [Operator Instructions]. As a reminder, this call is being recorded for replay purposes. And now I'd like to turn the call over to Mr. Mike Drickamer, the Director of Investor Relations. Please, proceed, sir.

Thank you, Michelle. Good morning, and on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the 3 and 12 months ended December 31, 2013. 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 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 the conference call. And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Mike, thank you. Good morning, and welcome to Patterson-UTI's conference call for the fourth quarter of 2013. 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 into the fourth quarter. As set forth in our earnings press release issued this morning, we reported net income of $16.6 million, or $0.11 per share. This included a $37.8 million pretax noncash charge related to our mechanically powered rig fleet, which reduced our reported earnings per share by $0.17 per share. Consolidated revenues for the fourth quarter were $659 million, and EBITDA was $216 million. Earnings for the full year 2013 were $188 million, or $1.28 per share, which included the fourth quarter noncash charge, as well as a $62.8 million of revenue from the early termination of 6 rigs in the third quarter, and $1.7 million of SG&A expenses in the third quarter related to the evaluation of, and preparation for, international opportunities. We are pleased with our fourth quarter financial results, which exceeded our expectations because of higher-than-expected rig count and average margin per day. Rising rig demand in November and December caused 2013 to end on a positive note. Utilization remained high for APEX rigs, and we were able to quickly respond to the increase in customer demand by reactivating non-APEX electric drilling rigs. Additionally, we achieved better-than-expected improvement in our average rig revenue per day with lower-than-expected average rig operating cost per day. In total, we generated $921 million of EBITDA during 2013, and spent a total of $662 million in CapEx to further strengthen our competitive positions in both contract drilling and pressure pumping. Investments in contract drilling were used to, among other things, add 11 new APEX rigs to the fleet, order long lead time components for further APEX construction in 2014 and for rig upgrades to strengthen our position as a technology leader in both walking systems for pad drilling and for natural gas as a fuel source. We ended the year with 124 APEX rigs in our fleet, marking a significant transition in our company's history, with 87% of our contract drilling EBITDA during 2013 derived from our APEX rigs or other electric rigs. Similarly, investments we made in pressure pumping were focused on strengthening our competitive position in this business. We significantly reduced our pressure pumping CapEx in 2013 as we transitioned from growing our fleet to focusing on improving the facilities and infrastructure necessary for us to profitably compete in what was a very competitive market. In addition to our investments in 2013, we returned approximately $115 million to shareholders, including dividends of $29.1 million and share repurchases totaling $85.8 million. In total, we repurchased 4.1 million shares of our common stock during 2013 at an average price of $20.83. Our balance sheet continues to be strong as we exited 2013 with $250 million of cash and equivalents, and a conservative 13.8% net debt-to-cap ratio. With that, I'll now turn the call over to Andy.

Thanks, Mark. Following our typical format, I'm going to start this morning with some commentary on our Drilling business and then finish with some comments on pressure pumping. We have seen an appreciable increase in rig demand since the end of October. Our average U.S. rig count increased from 178 rigs in October to 187 in December. For the fourth quarter, our average operating rig count in the U.S. increased to 183 from 181 in the third quarter, and the average operating rig count in Canada increased to 9 rigs from 8 in the third quarter. The higher rig count continued in January. As we recently announced, our rig count grew further in January to 188 in the U.S. and 11 in Canada. We again achieved better than 95% utilization of our APEX rigs during the fourth quarter and we were able to quickly respond to increasing customer demand by reactivating non-APEX electric rigs. During the fourth quarter, we recognized $2.4 million of revenues related to early contract terminations of 2 rigs. While these rigs were released on short notice at the end of the fourth quarter, with the strong demand for APEX rigs, we were able to quickly re-contract them. Excluding the benefit of early termination revenues during both the third and fourth quarters, our total average revenue per day increased $520 to $23,170 in the fourth quarter from $22,650 in the third quarter. Additionally, average rig operating cost per day decreased $240 sequentially to $13,510 in the fourth quarter from $13,750 in the third quarter. Accordingly, excluding the positive impact from the early termination revenues in both the third and fourth quarters, average rig margin per day increased $760 to $9,660 per day in the fourth quarter from $8,900 in the third quarter. Looking forward, we expect demand to continue to improve with our average rig count in the U.S. reaching 191 rigs in the first quarter as we complete 3 new APEX rigs in the first quarter and continue to reactivate other electric rigs. In Canada, we expect our average rig count in the first quarter will remain relatively flat sequentially at 9 rigs. While we believe day rates will remain relatively flat in the first quarter, and our average rig revenue per day is expected to be approximately $23,100, we expect that day rates will trend higher as we progress through 2014. Average rig operating costs per day are expected to be impacted by the typical increase during the first quarter and will increase approximately $100 to $13,600. As of December 31, we have term contracts for drilling rigs providing for approximately $946 million of future day rate drilling revenue. Based on contracts currently in place, we expect to have an average of 124 rigs operating under term contracts during the first quarter, and an average of 93 rigs operating under term contracts during 2014. Turning to our APEX rig new build program. We completed 3 new APEX rigs during the fourth quarter. At December 31, we had a total of 124 APEX rigs in our fleet. We plan to complete the construction of 20 new APEX rigs during 2014, of which, 10 are currently contracted. We continue to improve our rig construction process and are pleased that during 2013, we were able to reduce the construction cost of our base rig by approximately 10%. As well as across the industry become increasingly more complex with a greater focus on pad drilling and longer laterals, the amount of equipment required by our customers has increased. More customers are requesting additional items on rigs such as walking systems, natural gas powered engines, high-pressure circulating systems and high-torque drill pipe. We are being compensated for this equipment in addition to the day rate on the base rig, so that we can generate a reasonable return on the capital required for this equipment. We continue to see strong demand for pad drilling. During 2013, we upgraded 9 rigs of walking systems and currently budget to upgrade another 11 rigs of walking systems during 2014. Additionally, all of the new APEX rigs we complete in 2014 are expected to have walking systems, bringing the total size of our walking fleet to approximately 110 rigs at the end of 2014. We added new GE Waukesha natural gas engines to 7 rigs during 2013 and continued to upgrade rigs to biofuel. We believe that using natural gas as a fuel source is an important green technology as it both reduces the environmental impact of our services and generates cost savings. By December 31, we had 28 rigs configured to use natural gas as the primary fuel source, including 7 natural gas-powered rigs and 21 biofuel-capable rigs. We budget to add GE Waukesha natural gas engines to 2 rigs and upgrade 17 rigs with biofuel systems during 2014. Turning now to pressure pumping. As expected, the seasonal decrease in activity during the fourth quarter resulted in a sequential decrease in pressure pumping revenues to $234 million. Despite this decrease, our gross margin modestly improved to 21.5% of revenues as we were able to control costs. Accordingly, pressure pumping EBITDA decreased less than $5 million during the fourth [ph] quarter to $45.8 million in the third quarter. As previously discussed, we had 90,000 horsepower under take-or-pay term contracts that rolled off at the end of 2013. Based on our current utilization outlook for this equipment, we believe this horsepower will remain active in 2014 and continue to generate reasonable profitability. In the first quarter, despite the horsepower that rolled off contract and weather delays in the Northeast resulting from the extremely cold temperatures, we expect the sequential improvement with pressure pumping revenues increasing to approximately $260 million and gross margins remaining relatively flat at 21% of pressure pumping revenues. As Mark mentioned, in 2013, we focused on strengthening our competitive position in this business through excellent well site execution, the introduction of new technologies and investment in new facilities. In the third quarter, we moved into a new facility in Midland with more laboratory space for the quality control testing of frac cement and acid service chemistry. As customers focus on securing new and environmentally friendly sources of water for hydraulic fracturing, this new facility has been especially been efficient in testing recycled produce water in order to blend the appropriate gel chemistry to maximize well productivity. Enhanced maintenance facilities at this new location also improved the efficiency, which we are able to maintain our equipment to ensure high levels of customer service in the Permian. We also introduced the new powder steam technology in 2013 for hydrating powdered friction reducers at the well site. This technology, which we tested for over a year, gives us an advantage on the cost and on the quality of friction reducers needed for recycled produced waters using fracturing treatments. Additionally, in 2013, we began upgrading frac-ing equipment to use natural gas as a fuel source. And we believe we are a leader in biofuel frac technology. In the Marcellus, we have completed more than 600 stages using natural gas as a fuel source. And in drilling, we believe that natural gas biofuel's an important green technology as it both reduces the environmental impact of our services and generates cost savings with our biofuel frac-ing that's able to cut diesel fuel consumption in half. To date, our biofuel frac units have replaced over 332,000 gallons of diesel with lower cost and cleaner burning natural gas, and thereby eliminated more than 2.4 million pounds of transportation loads on local roads. We are optimistic about the outlook for our pressure pumping. The increasing focus on horizontal wells, combined with an increased well count in 2014, should lead to increased pressure pumping demand for our services. Before I turn the call back to Mark for his concluding remarks, let me provide an update on a couple of other corporate financial matters. Our consolidated CapEx budget for 2014 is approximately $950 million, of which, contract drilling accounts for approximately 3/4. We expect our effective tax rate to decline to approximately 32.7% in 2014 compared to 36.6% in 2013. To save some Q&A on this topic, let me explain. In recent years, our federal cash tax payments have been reduced as a result of bonus depreciation for tax purposes. This deduction accelerates the first year depreciation deductions and reduces cash tax payment, but does not reduce the effective tax rate for financial statement purposes. Federal income tax provisions allowing bonus depreciation deductions expired at the end of 2013, which is expected to result in cash taxes of approximately $50 million above our 2014 effective tax rate. Although bonus depreciation reduced our cash tax payments in recent years, it prevented us from taking advantage of the permanent tax rate reduction benefits associated with the domestic production activities deduction. Beginning in 2014, we will benefit from the financial statement tax rate reduction associated with this deduction. SG&A during the first quarter is expected to be $18.5 million. Depreciation expense during the first quarter is expected to be $148 million. Finally, let me remind you that the Canadian rig count in the second quarter will be impacted by the seasonal breakup. During the second quarter, we typically average approximately 2 active rigs in Canada, and produce a small operating loss in that market as a result of reduced rig activity and seasonal repairs. With that, I will now turn the call back to Mark to offer his assessment on our performance in 2013.

Thanks, Andy. I'd like to share some thoughts with you about Patterson-UTI's strong performance in 2013, and how I think that performance positions us for a strong 2014. By way of background, in 2013, the average U.S. industry land rig count decreased 9% from 1,852 to 1,685. At the same time, our industry experienced a 4% decrease in rigs drilling horizontal wells accompanied by a 22% decrease in rigs drilling vertical wells. As if these 2 cross current trends were not sufficient, we also experienced a continuing shift away from natural gas to oil and liquids. A few years ago, 80% of the rigs were targeting natural gas. Last year, about 80% were targeting oil and liquids. The speed of change is shocking. It was about 50-50 in 2011. At the same time, pad drilling accelerated. These fundamental changes in our industry profoundly affected the equipment, drilling in pressure pumping and the personnel needed by our customers. Against this mostly flat to negative backdrop, Patterson-UTI shareholders enjoyed a strong year as total shareholder return was 37%, outpacing even the very strong S&P return. We believe that this strong return arises from our customers appreciating the depth and quality of our businesses, both drilling and pressure pumping fleets, and from our highly skilled and trained personnel. We needed to upgrade both our drilling rigs and pressure pumping equipment and have done so in a very dramatic way over the past 7 years. But it's not just equipment. We have invested heavily in recruiting and training our people and we believe that we have now differentiated ourselves by the high quality of service offering that we provide in both drilling and pressure pumping. We have both equipment and the crews customers need to execute their plans efficiently and safely. In essence, we were able to change so that service work changed, so that as the service work changed, we were ready to supply the needed equipment and needed personnel. In turn, many of our investors have come to recognize the company's transformation has resulted in a sustainable business model, well positioned for the developing service industries in which we function. In essence, Patterson-UTI is well-positioned to provide 2 of the most essential services needed as the shale revolution continues and expands. One way to see this trend is in utilization rates for APEX rigs. Over 95% of the year, despite the slowdown in industry drilling activity in 2013. We believe that this utilization is ahead of what other providers achieved for their advanced fit-for-purpose rigs and reflects both the quality of our rigs and drilling operations. Another indication of this arises in pressure pumping. Despite fierce competition in the industry, we never had to stack any of our crews. In fact, we actually added 45,000 horsepower in the first quarter at acceptable pricing and margins. We proved that we are able to compete based on the quality of our service against others who offered more aggressive pricing. Our strong focus on well site execution and customer satisfaction softened for us but proved to be a pretty hard year for many of our competitors. We are highly optimistic about prospects for our business based on our success in 2013. Our customers know that we are a reliable supplier of the services they require, and we'll be flexible and creative in meeting their changing service needs. We have changed, are changing and continue to recognize that further changes will be needed given the dynamic nature of our industry. We have built a strong base of advanced drilling and pressure pumping equipment and personnel and demonstrate our adaptability to future needed changes. This bodes well for strong growth in 2014 and thereafter. Given the transformation in our company's fundamentals, I'm pleased to announce today that the company declared a quarterly cash dividend of $0.10 per share, doubling our previous quarterly dividend. This dividend will be paid to shareholders on March 27, 2014, to holders of record as of March 12, 2014. The transformation of our company with state-of-the-art drilling and pressure pumping fleets has benefited us through more term contracts and greater consistency in our revenues and cash flows, thereby increasing our ability to return capital to shareholders. Our board doubled the quarterly cash dividend in recognition that the company's transformation has had a profound impact on our financial results. For example: first, our revenue growth -- our revenue has grown substantially and averaged $2.7 billion over the past 3 years; second, our average EBITDA during the same period has been approximately $970 million, almost a 30% increase from the prior 5-year period; and third, we concluded 2013 with a strong balance sheet and a low debt-to-cap ratio. We embark on this higher payout to our shareholders based on our belief that we are now, as a result of a multiyear investment program, a far stronger company with significantly improved businesses and prospects. With that, I would like to both commend and thank the hardworking men and women who make up this company as it was their focus on the customer that helped to differentiate us. Operator, I would now like to open the call for questions.

[Operator Instructions] The first question we have comes from Robin Shoemaker of Citi.

I wanted to ask about as you have APEX rigs contract -- term contracts that come up for expiration or renewal, are -- and you mentioned you have 93, I think, committed for the full year on term. But are you continuing to sign -- or are you signing term contracts for existing rigs, not new builds but existing rigs, as they finish off their existing contract? Or are those rigs typically going to more like a spot? Or is it versus some of each?

Robin, this is Andy. Yes, as we have rigs that roll off contract even -- whether they're new builds or other rigs that are on contract. Many of these rigs go back into term contracts at favorable pricing. And especially in today's market, as the demand for our high-spec APEX rig just continues to stay strong. We're very pleased with the situation and the discussions that we're having with the customers.

Right. Okay. So the figure you gave just for the full year term contracts, that's just your backlog, as I understand, as of now?

That's correct. Yes.

Okay. Okay. So then turning to pressure pumping. And you've mentioned the expiration of a legacy contract, which rolled off, but can you characterize the current environment for contracting your pressure pumping equipment? Is it -- are you signing term contracts? Not the take-or-pay kind that previously existed, but more like term commitments? Or are you working more spot-type arrangements? And has the pricing, in any way, changed from where it was toward the end of last year?

Well, I'll frame it up for you this way. So we did have 90,000-horsepower that was rolling off at the end of Q4, so it becomes a Q1 event. These contracts are recently signed back when pricing was higher. We had given some concessions during the course of these contracts on the pricing as the market got more difficult. It's still a bit of a challenging market, but we expect these crews to stay busy going forward. So these crews will be dedicated on some of the contracts that we're entering into going forward. And as you heard earlier, we expect margins to stay roughly flat at about 21%.

The next question we have comes from the line of Jim Wicklund from Credit Suisse. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Where are you putting the non-APEX, the electric rigs that you're putting back to work? Where are you -- where are they going?

They are actually going in a mix of places, as you can imagine. There's very high demand out at Permian and West Texas, right now. So some are going there, some are coming up in mid-continent, East Texas. So it's just been a mix across the U.S. James Knowlton Wicklund - Crédit Suisse AG, Research Division: And have these rigs been upgraded? I know there's several different ways by some of the equipment manufacturers to make an old SCR look very much like a brand-new electric rig. Have you had to do any work on these? Or is this just the incremental demand for electric rig?

It's really just incremental demand for rigs. And there's a shortage of high spec rigs like our APEX out there, right now. We're utilization of roughly 96%. And so with that kind of demand, we're also seeing demand for the non-APEX electrics. And we haven't had to spend a lot of money. We haven't done any major work on these rigs. They were in good shape and pretty much has put them back to work. Some of them already had upgrades. Many of them have top drives, ST-80 Iron Roughnecks. Those things already existed in those rigs. James Knowlton Wicklund - Crédit Suisse AG, Research Division: That's pretty good. Nice going. And Mark, you talked about gas drilling and one of those rapid switches in the history of mankind. What is the outlook for natural gas drilling, dry gas drilling in 2014? Gas is $5.15 this morning, are we going to start drilling for dry gas again this year?

Jim, I sure wish I knew the answer to that question. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Me too.

Exactly. I don't think we have any visibility on that, that we could offer that would be, at all, helpful. Quite honestly, if you want just a little by-play, at our board meeting yesterday, there was some discussion by various board members about whether it was a $5 number that we get at the market active or a different number, and so lots of people with lots of opinions, but I don't think we uniquely have anything to offer on that topic.

I'll add, over a period last year, you saw rig count go up by a couple of rigs in the Marcellus, a couple of rigs over East Texas, Haynesville. And we received some questions about that time, well, just based on the fact that natural gas prices are moving up. And even at that point, it didn't because it had been based more on long-term decisions that operators were making, not necessarily because of the immediate movement of the natural gas prices. James Knowlton Wicklund - Crédit Suisse AG, Research Division: Okay. That makes sense. We raised our gas price with a year-to-date of $4.30. So I'm still not sure that spurs whole lot of the dry gas activity. Last question if I could. Andy, what's your biggest source of inflation in your business today, if there is any?

Actually, we're pleased that we seem to be holding costs in line. Labor is 2/3 of our cost, but we have a national recruiting program. So even though we're seeing growth out in West Texas, Permian, the Midland area, we're not trapped in a recruiting situation where we're just recruiting from that area. We're recruiting across the country and so we see those labor costs holding relatively steady. So overall, our costs seem to be holding relatively steady.

The next question we have comes from Marshall Adkins of Raymond James. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: I do certainly applaud your ability and success at getting more cash back to the shareholders. And Mark, you gave us a little bit of insight into the thought process. Could you give us a little more color at the board level on the thought process behind dividend versus stock buyback, and I guess, more importantly, the comfort level you obviously have with giving more of this cash back to shareholders?

Well, I'm happy to do so. I guess, the thing I'd like to just maybe start out with is for people who maybe not as familiar as you are, Marshall, with our history, is to tell people that so far sort of from the time this management got involved in the company, we've given back to shareholders in either the forms of dividends or buybacks over $1,225,000,000 going way back of which, probably without having a calculator to do it, I would guess 2/3 of it was in buybacks and 1/3 of it was in dividends. We believe in both mechanisms as ways of returning excess cash to shareholders. There's times in which it's more opportune from our perspective to do so through buyback, and other times, which is more opportune to go through the dividend route. At this point, as you know, we have had a dividend, which we instituted in 2004. I think we were among the very first of the service companies, especially that time, smaller service companies, to reinstitute a dividend just as a follow-up of a change in national tax policy. That dividend went up, as you know, pretty lockstep. Unfortunately, we didn't have a sense that the market necessarily rewarded us, as well as we hoped it would. We think that now, with a much stronger company and a much -- that was obviously the point of the comments that I made in the prepared remarks, that we think that and are hopeful that the increased dividend will be appreciated by the shareholders. And if so, we wouldn't rule out the possibility of thinking about additional increases. J. Marshall Adkins - Raymond James & Associates, Inc., Research Division: Awesome. Great to hear. Andy, one quick one for you. The cost side went down this quarter. Is that a function of more throughput, better utilization? Is it a mix issue? Or is some of that the biofuel stuff? If I'm right, 50 rigs or something, by the end of this year, you'll have this biofuel or nat gas? Help me understand why the costs went down, I guess.

Yes. First, I'll start on the biofuel and the natural gas. So our customers wanted really to get the benefit in the contracts on the drilling rigs. It's the customer that provides the fuel. And so that's where the real benefit is for them and that's where the demand is coming from. If you look at our cost in the Drilling business in general, our operations people are doing a great job controlling the cost. At the same time, with the rig count coming up, it becomes a mix with a numerator/denominator function. And so with the rig count growing, we're absorbing more of the cost into the business at the same time.

The next question we have comes from the line of Kurt Hallead. He's from RBC Capital Markets.

So I want to follow up on a couple of things here. First and foremost, Andy, in your prepared commentary, you talked about the -- or Mark, I can't figure which one at this point, age creeping up on me here. But you talked about preparation for potential international opportunities. Could you expand on that a little bit more? And what are you thinking? Is it land? Is it frac? Is it both? Is it Western Hemisphere? Is it Eastern Hemisphere? Some expanded thoughts on that, please?

Sure. So back in Q2 at our call in July, we addressed that we had spent $1.7 million looking at opportunities outside the U.S. and incurring some cost in professional fees in that process. We continue to work through this for us. This is part of the long-term strategy for Patterson-UTI, not something that will materialize overnight. It's going to be organic growth for us and we're taking it slow and steady to make sure that we get it right and that we can maintain costs in line at the same time. So nothing that's progressing at any quick speed but something that we're doing at a very measured pace.

So how do you know there -- this business, it's kind of littered with horror stories of companies who did really well in North America, expanding overseas. And I don't have to go through that whole laundry list of companies. I'm sure you're well aware of them. For an entity that's really cautious in North America like you guys do, how do you think about the cost benefit of potentially diluting why investors are involved in your stock?

For us, the international market is not any kind of commentary on North America. But we certainly believe that the North American market is still -- has strong demand for our services, especially when it comes to retooling the rig fleet. We're going to continue that for several years. And there's certainly that demand in North America for that to happen and continue to improve the margins. For us, looking at international is really about an even longer-term strategy with Patterson-UTI. And what potentially happens for us in other markets outside of North America, as the U.S. market start to end the retooling of industry over the next few years. So we're certainly very aware of the challenges in moving outside of North America and potential costs. But the same time, we think there are opportunities in some key regions, and we continue that work.

Kurt, if I can just jump in here and just say one thing. Your comment about the world is littered with people who try to do this and fail, one of the things that I think you've probably experienced with us is that we're okay in thinking about things in 5- and 10-year periods and acting sort of carefully and thoughtfully to get to the result we want. The view, I think, among our management is that there are, in addition to the wonderful opportunities in North America, which are we would quickly add supremely attractive, and obviously that's where we're primarily focused. But we believe that over the next 5, 10 years, there will also be opportunities, particularly in selected, carefully chosen, thoughtfully deployed regions, worlds, areas, countries. I don't want to get specific here. But we think there will be particular opportunities. And we think that if you go about it with the same kind of focus and the same sort of thoughtfulness that we've done other work, we can profit by it and add to the shareholders' overall returns and not dilute their U.S. returns. So you're hearing it from someone who's obviously very concerned about that, that we think it's a very good move, but a move that has to be made slowly and carefully.

Okay. One follow-up here would be -- it's on the guide points you provided for U.S. land business in the first quarter. I think you indicated -- or North America, I should think, including Canada, you indicated a slight day rate decline. You can call it flat, whatever, a slight decline, a slight increase in operating costs, so cash margins coming down sequentially, first quarter relative to fourth quarter. First, what's the -- why the change in the day rate on the downside, given some of the dynamics that are at play here with increased demand and high utilization? It seems to me like there should be more pricing power prevalent. And then on the cash margin progression, once you get beyond the first quarter, how are you guys thinking about cash margin progression generally?

So as you look at quarter-on-quarter, what you're seeing is a combination of a couple of things. There's rig mix and the rig count with high-spec APEX rigs along with SCRs and mechanicals in there. So that's going to make up that bit of difference, which is not a big amount. There's also, as we increase the rig count in the U.S. relative to Canada, so it comes down a little bit just from that as well. But back to the discussion on pricing, our pricing held very strong through 2013. And as we mentioned earlier, we expect it to move up towards the end of 2014. But that's what you're seeing right now in those average numbers going quarter-to-quarter.

What about the cash margin? How do you guys think about that? Obviously, with day rate moving up in the back half, I get that dynamic. But is it more day rate-driven? Or is there some efficiency dynamics that could help reduce operating cost from where you kind of averaged in the last couple of quarters?

Kurt, we've had a long history of really speaking only to the next quarter on the theory that the visibility wasn't much better than that. And so everything was, from our perspective, kind of a speculation that we let you and your colleagues make those judgments about as well as we can make them. Frankly, there's a little cost in the first quarter that everybody is aware of as we wind up with the first quarter. Like the various other kinds of costs, we've got, I think, $100 in that in terms of first quarter increase in costs. And ultimately, what I think you heard is as an answer from Andy earlier that we're really seeing costs stay pretty nicely controlled at this point. Whether we'll see that change over the year, real difficult to give you a lot of visibility on that. That's why we typically only speak to this quarter.

The next question we have comes from the line of Brad Handler from Jefferies.

Could you please speak to your -- a little more color, I guess, please, about your pressure pumping revenue guidance in Q1? Perhaps just to sort of tee it up, I might have thought there was -- you would seem to allow for some pricing decline on the 90,000-horsepower that rolled off contract. There are usually some seasonal influences that dampen the activity in Q1. So maybe just set against that backdrop? But again some more color would be very helpful.

Sure. There's different moving pieces in pressure pumping with us servicing the market in the Northeast and in the Southwest. What we're also seeing in Q1 is an increasing backlog of wells, of stages per month. So you're seeing an increase in revenue there. And at the same time, as we discussed earlier, even though we've had 90,000-horsepower roll off and that becomes a Q1 event, we feel good about holding the margins steady quarter-on-quarter.

Got it. So presumably, the January started off at a quick pace and you've got sort of a visibility obviously on the rest of the quarter that's driving from an activity standpoint. That's fair if that's what you're saying.

No, I wouldn't say that. We've had a lot of cold weather that's affected the Northeast at the same time, but we have a backlog of wells in front of us at the same time.

Got it. So weather allowing, that's where you should be able to -- from an activity standpoint, that's where you should be able to get to, I guess. Okay. Curious about the -- if you can comment on whether, first of all, your sense of leading-edge pricing across basins that you participate in, in pumping. And then to the degree that within that guidance, yes, there is still some average pricing down, which is I'm just trying to get a sense of if that's true.

The market at this point is still oversupplied. But what we're seeing in the market, it starts with drilling. We see an increasing rig count in 2014, especially around high-spec rigs, which means more horizontal wells, which has a potential to increase well count, increase stage count per month and improve utilization. When we say utilization, remember, we don't have any crews that are stacked, but it has to do with filling holes in the calendar. Overall, pricing is holding steady and we have an opportunity to fill some holes in the calendar with the backlog in front of us.

Brad, I just would comment. In our prepared remarks, we spoke to the fact that we expect sequential improvement with pressure pumping revenues increasing to $260 million and gross margins remaining relatively flat at 21% in pressure pumping revenues. And so what we're telling you is effectively that notwithstanding the rollover on the contracts, the cold weather -- and I just want to make a point here that our Northeast operation historically is operated in January in cold weather. When it gets to be below 0 or minus 5 degrees, that's when it becomes a real factor for us. But in any event, those numbers were given in light of all of what we now know about the weather. Obviously, we don't have next week weather or next month's weather, but we do know what the weather has been so far today.

Sure. No, I appreciate that. If I could just slip in one more, please, bouncing back up to your contract drilling business. I guess, I'm curious, you are reactivating some SCR rigs. I'm curious whether you have any sense as to whether or not that's providing a bridge for customers that are perhaps ordering one of your APEX rigs? In other words, is there some element of, as you build, you will be replacing some rigs that have been brought back into service to fill that gap?

It's a good question, and that's a question that's come up through 2013 as well. What does it mean for the non-APEX rigs? What we see so far with what we've contracted on the new high-spec APEX is that the SCRs and even the mechanicals that are working are not working as bridges for the contracts that we're signing today. These are just with different customers and there's just demand for rigs out there.

The next question we have comes from the line of John Daniel from Simmons. John M. Daniel - Simmons & Company International, Research Division: Andy, your CapEx guidance, if I heard correctly, would suggest we'll see something like $200 million allocated to the pressure pumping business. Just taking 25% on that, the total budget. Assuming that's directionally right, should we then assume that you're adding incremental fleets this year?

So it's a good question, and I'll break it down a little bit for you. So we talked about a total of $950 million in CapEx budgeted for 2014. That breaks out to $700 million for drilling, $210 million for pressure pumping. And when you look at the $700 million in drilling, it's approximately $520 million that are new rigs and also upgrades on rigs that are out there in the fleet today. Then there's around $180 million that is maintenance facility, vehicles, others, bits and pieces for the Drilling business. In pressure pumping, $210 million in total. Approximately $150 million goes for maintenance facilities, vehicles, sand storage, various pieces of equipment that we're going to add. We've also budgeted $60 million to add new capacity if we feel that the market warrants it in 2014. It's in the budget, but it's kind of a wait-and-see right now. John M. Daniel - Simmons & Company International, Research Division: Okay. So it hasn't been ordered yet then?

No. And then there's another $40 million in CapEx for E&P. John M. Daniel - Simmons & Company International, Research Division: Okay. When you look at the revenue guidance for pressure pumping, it's clearly very strong. And you suggest utilization is fairly high. Given that backdrop and given your comments about optimism on the business as the year unfolds, how realistic do you think it is that we see some pricing opportunities this year? And do you need to see that happen before you place the order for the new equipment?

As I mentioned a few minutes ago, the pricing in pressure pumping seems to be holding stable. We'd like to see in the industry a few of the fleets that are parked on the sidelines come back to work at the same time. But as high-spec rig count increases, as I mentioned earlier, and we get an increasing well count in '14 along with stage counts, there is the possibility we're going to see higher utilization for us. It means filling out the calendar. We'll just wait and see how it goes through the year before we decide if we need to add or activate any more horsepower like that. John M. Daniel - Simmons & Company International, Research Division: Sure. But I guess, where I'm going with this, Andy, is would you need to see pricing move higher before you place the order for new equipment?

Our guys have been doing a good job holding the margins in a very tough market. And we'd like to see that inch up a little bit. But again we'll just keep an eye on things. There's also the aspect when you're working for some good customers that need more help, sometimes you're willing to work with them on things. But again we'll just watch the market and see how it goes.

I would just add one small thing. You're sort of suggesting the decision about adding to the fleet is kind of truly binary. It's like price direct, therefore we do it. And I'm trying -- I think Andy's answer is that it's multifactored, it's customers, it's pricing, it's margin, it's what we see other competitors doing, it's a whole series of things, all of which you've got to take into account. So it's not really as binary... John M. Daniel - Simmons & Company International, Research Division: No, I get that, Mark. I get you. I guess, what I'm just looking at -- the revenue guidance for Q1 is clearly very strong, probably surprised a lot of people, but the margins are still relatively flat. And one would normally think that with that type of revenue growth, you might get some margin uplift. And so that's why I'm pressing on the price comment just where margins are and that [ph] high utilization. That's all.

Yes. And back to the discussion earlier, we had the rollover of contracts from Q4 into Q1. That's an end mix as well. We do expect activity to improve, revenue to improve. Pricing, as I mentioned earlier, kind of holding steady right now, not clear when we're going to get some pricing traction in the market in pressure pumping. There's still some oversupply out there. But if we see some of these fleets come off the sidelines. We'll look at the big picture and make some decisions on what to do.

The next question we have comes from the line of Waqar Syed from Goldman Sachs.

Just a clarification. I think I know the answer. But all the early termination revenues in drilling were all U.S.-based. Is that correct?

That's correct.

Okay. Could you provide a breakdown of this, 188 rigs, 190 rigs that are going to be working in the first quarter? What could be the breakdown between APEX, SCR and mechanical?

I don't think we have the patience sitting here. I mean, we have the information, but I don't think we have it...

Don't have that in front of me right now.

Okay. And then the tax rate improvement that you're seeing, is it likely to flow into '15, '16 onwards as well? Or do you think you get the benefit more in '14, and then it start to taper off?

First, I'll answer the -- back to the rig discussion, I'll mention again, we are planning to deliver 3 new APEX rigs into the mix in Q1. So you can factor that into the rig count number versus what we exited 2013. But as far as the tax question going forward -- I think, John, do you want to answer that...

You probably want to repeat the tax question for...

Well, what I was saying is that the tax benefit this year, does that flow through into '15, '16 as well? Or is that just a '14 phenomena?

No. Under current tax law, it would continue. As Andy said in the prepared remarks, the bonus depreciation provisions expired. We thought they were going to expire at the end of '12, they got extended another year through '13. But the current tax law, we would expect the rates to work in a similar way. Frankly, there's a little bit bigger impact on cash taxes in the first year of this because due to bonus depreciation, a lot of the rakes are highly depreciated for tax purposes. As we invest more in the fleet, we would actually reduce cash taxes a couple of years down the road. Waqar, I do not have the breakdown of APEX versus other electric here. But off the top of my head, we've been running about 35 mechanical rigs on a stable space for a number of month of now. So the vast majority of our rig count is APEX and other electric. And as mentioned, frankly, the mechanicals are a very small percentage of our EBITDA deployment.

The next question we have comes from the line of Byron Pope from Tudor, Pickering, Holt. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just given the strong AC rig demand in the market, it seems fairly safe that the 20 APEX rigs we'll bring out this year will find homes at good day rates. As we think about the potential for further non-APEX electric rigs to potentially go to work, Andy, the way I heard you describe some of the rig capabilities and some of the features that the customers are asking for, I think those SCR rigs that potentially could go to work during the course of 2014 is being added to the overall fleet mix. And from a revenue or from a margin perspective, I just wanted to test that notion to the extent that we see further SCR rigs go back to work this year.

You'll just have to kind of stay tuned and see what our rig count looks like on the website and how things progress. We are in discussions with customers. We've talked about the demand being strong. We're going to deliver 3 new APEX in Q1. Our mechanical rig count has been holding steady. And you saw in Q4 where the nonelectric APEX rig count actually went up. So we've certainly been pleased with the demand that we saw right there at the end of Q4 and the discussions with the customers continue. Byron K. Pope - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then on the pressure pumping side of the business, I think in Q3, you guys were roughly 3/4 of your overall frac work on 24-hour type work end. I'm assuming that mix didn't change much in Q4, aside from weather. And just thinking about it in 2014, is there room for that mix to be even higher just given you've got more customers on multiwell pads?

We're pleased to actually see that mix hold steady in Q4. There is that chance in 2014 when you talk about higher well counts and higher backlog of wells and stages that needed to be done that, that could increase a little bit. A lot of it depends on the customer and the program that they have and are they set up to manage getting water for 24-hour operations, having a well in stage backlog for 24-hour operations. There's no question our crews can manage that. So if there is the potential for that to increase with the increasing well count, our equipment with a very relatively new fleet and the people that we have out there, a good position to manage that.

The next question we have comes from the line of Jud Bailey from the ISI Group.

Most of my questions have been answered, but I wanted to ask -- circle back on some of the reactivations. The conversations you're having with customers, what's the profile that you're talking to? Are these -- are they a mix of private and some of the bigger independents? Or is it more of a larger independents?

It's absolutely across the board. One of the things that we pride ourselves on at Patterson-UTI is we have a very broad customer mix. We work for some of the smallest operators out there and some of the largest in the world at the same time. And so these are ongoing discussions with a variety of different customers.

Okay. And based on the conversations you're having today, I mean, I guess, can you give us a sense of maybe how many rigs could reactivate in the next, I don't know, 90 days above what you've already agreed to at this point?

No. We've talked about what we think is going to happen in Q1 and certainly don't want to speculate further than that right now.

Okay. And just one last one for me then. And John, you mentioned your mechanical rig count has been pretty flat in the low 30s. Any reason that, that goes up or down materially in your mind based on what your customers are telling you? Are there any guys who may want to grab a mechanical rig to drill some oil wells? Or do we count on that staying flat?

Yes. If you looked at the several releases, we talked about mechanical rigs. We've got about 55 market rigs on the sideline in the mechanical category. And we took charge related to those because as we sit here today, we have not seen a lot of incremental net demand for mechanical rigs. If you think back to earlier conversation call about higher gas prices, what might that mean, if people began to start drilling vertical gas wells, we'd make a lot of money with those rigs. But today, we have not seen that trend. Instead, we've seen a stable-state mechanical rig count, where it's contributing somewhere around $100 million of EBITDA a year, helping us buy new equipment. And we continue to appreciate those profits, but we have not seen any improvement in the rig count for that.

Yes. I would just characterize it as holding steady.

We have another question that comes from the line of Doug Dyer from Hartland Advisors.

Just a quick one here. Industry-wide, if you think that the industry needs another 50 rigs this year, do you think there are enough services to keep up with that kind of demand?

I think there are. I mean, there's -- overall, our rig count is down from where it was a few years ago. I think there's enough services of the different types of services that are required to complete drilling complete wells. We've talked about pressure pumping for a while, saying it's been a tough, oversupplied market. There's still some fleets that are sitting on the sidelines. And so we certainly anticipate as well count grows in 2014 that some of these fleets will probably get back to work that other companies have stacked. Our crews have stayed busy. We haven't stacked any of our fleets, but we have had some holes in the calendar. And we're upbeat about filling some of those holes in the calendars going forward.

Okay. One more quick one. Do you have any kind of a ratio or a guesstimate as to when an APEX rig rolls out or a competitors' high-spec rig, how many older rigs does that displace in terms of capability? Is it 1.5 or 2? Or is there any way to know what that is?

Well, actually, if you look at what happened to us in Q4, we put 2 new APEX rigs out into the market and we increased our SCR rig count at the same time. So in that particular scenario, we weren't displacing any rigs. The demand is high enough for rigs overall that we're not seeing it. Well, we didn't see that displacement in Q4. And it really depends on the customer and the region at the same time.

We have one final question and that comes from the line of Alexander Newcastle [ph] from Global Hunter Securities.

Just one quick question on the new build schedule. Beyond Q1, are the new build deliveries split out pretty evenly? Or are they weighted towards a specific quarter?

I think beyond Q1, you can just kind of look at them as evenly spread. There's different moving parts, depending on when customers require a rig to start up but we're just focused on Q1 right now. And as we said, we're delivering 3 in Q1.

Okay. And your natural gas and biofuel upgrades, are those mostly rigs coming back from the fields or rigs you already have stacked? And how long do those normally take?

So those are rigs that are out working in the field and those are pieces of equipment. When it comes to biofuel, that's something that can be added on the rig during a rig move. The rig doesn't have to come back to a yard to have any kind of service done.

Thank you. There are no further questions coming through. Do you wish me to close the call now?

Operator, I just would thank all the participants for their being with us on this call and look forward to speaking with everybody when we report our first quarter numbers in April. Thanks, everybody.

Thank you. Ladies and gentlemen, that concludes your conference call for today. You may now disconnect. Thank you for joining and enjoy the rest of your day.