Patterson-UTI Energy Inc (PTEN) 2018 Q4 法說會逐字稿

Good morning, my name is Adam, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy Fourth Quarter Earnings Conference Call. (Operator Instructions)

Mike Drickamer, Vice President of Investor Relations, you may begin your conference.

Thank you, Adam. 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 fourth quarter and full year ended December 31, 2018. Participating in today's call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer.

A quick reminder that statements made on 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 and 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 from what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statements. 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 2018.

We are pleased that you could join us today. This morning, I will turn the call over to Andy Smith, who will review the financial results for the quarter ended December 31. He will then turn the call over to Andy Hendricks, who will share some comments on our operational highlights as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over to questions.

Andy?

Thanks, Mark. As set forth in our earnings press release issued this morning, for the fourth quarter, we reported a net loss of $201 million or $0.93 per share on revenues of $796 million. Included in our net loss is a $211 million noncash pretax impairment charge. Excluding this charge, our net loss for the fourth quarter would have been $9 million or $0.04 per share. With respect to the impairment, we performed a quantitative impairment assessment of our goodwill as of December 31, 2018, due to the decline of our stock price and the deterioration of crude oil prices in the fourth quarter of 2018.

In completing the assessment, we recognized a noncash charge for the impairment of all of the goodwill in our pressure pumping and directional drilling reporting units. Consolidated adjusted EBITDA for the fourth quarter was $213 million, which brought total consolidated adjusted EBITDA for 2018 to $806 million, an increase of $315 million or 64% over the prior year.

During the fourth quarter, we repurchased an additional 3.8 million shares of our common stock at a total price of $50 million. This brought our total market repurchases for 2018 to $150 million or 9.3 million shares, which represented 4.2% of the company's outstanding shares at the beginning of 2018. In addition to the buybacks, we paid our regular quarterly dividend of $0.04 per share, which resulted in an additional $8.6 million returned to shareholders during the quarter and $30.6 million for the year.

In total, we returned $181 million of cash to shareholders during 2018. We will continue to evaluate opportunities to repurchase our shares, particularly when we feel our stock is significantly undervalued. At December 31, 2018, we had approximately $150 million remaining under our share repurchase authorization. And yesterday, the Board increased this authorization to $250 million.

At December 31, 2018, we remained modestly levered with a net debt to capital ratio of 20.1%. Cash capital expenditures for 2018 totaled $641 million. Additionally, we sold approximately $47 million of miscellaneous assets during the year, resulting in net cash CapEx of $594 million.

For 2019, based on near-term activity levels, we expect cash used for capital expenditures to be approximately $465 million, which includes approximately $40 million of cash to be spent in 2019, associated with major rig upgrades delivered in 2018 and early 2019. As a reminder, all of the major rig upgrades are supported by contracts. The remaining $425 million of planned spend in 2019 is projected among our segments as follows: approximately $225 million in drilling, of which approximately $145 million represents maintenance expenditures; $120 million for primarily maintenance capital expenditures in pressure pumping; $25 million for directional drilling, of which $10 million is maintenance; a combined $35 million for our Oilfield Rentals, Technology and E&P businesses; and $20 million for general corporate purposes.

For the first quarter, depreciation expense is expected to be approximately $214 million, SG&A is expected to be $33 million and our effective tax rate is expected to be approximately 23%.

With that, I'll now turn the call over to Andy Hendricks.

Thanks, Andy. In contract drilling, our rig count during the fourth quarter averaged 183 rigs, an increase of 5 rigs from the third quarter as demand for super-spec rigs remained solid during the fourth quarter. Average rig margin per day increased $920 to $9,390, driven by a $690 increase in average rig revenue per day and a $230 per day decrease in average rig operating cost per day. Average rig margin revenue and cost per day were all better than expected.

On a year-on-year basis, our rig count in the fourth quarter was 22 rigs higher than the fourth quarter in the prior year. This increase in activity, primarily in super-spec rigs, drove an increase in average revenue per day of $2,020 for the same period. I would like to commend our rig operations group for their focus on operational excellence, which allowed us to achieve higher dayrates. At December 31, we had term contracts for drilling rates providing for approximately $770 million of future dayrate drilling revenue. Based on contracts currently in place, we expect an average of 122 rigs operating under term contracts during the first quarter and an average of 78 rigs operating under term contracts during 2019.

During 2018, we completed 14 major rig upgrades and we have completed 1 major rig upgrade this year. We have 1 additional major rig upgrade to be delivered in the first quarter of 2019. Within our fleet of 198 APEX rigs, 149 have super-spec capabilities and the remaining 49 rigs could all be upgraded to super-spec capability. Given the significant capital investment for major upgrades, we require term contracts for a major upgrade. We have not delivered any major drilling rig upgrades without a term contract nor do we intend to do so.

2018 was a year of continued bifurcation in the U.S. drilling market as super-spec rigs gained market share due to their efficient and reliable operations. Within this market, Patterson-UTI maintains its position as a leading super-spec driller. We estimate the current available supply of super-spec rigs in the U.S. is approximately 650 rigs. And we believe current industry utilization for super-spec rigs is in the mid-90s percent range. In addition to the advancements made in the super-spec rig market, I want to commend our team for the operational achievements in technology advances in 2018.

Our first new APEX-XC class rig, which was originally delivered in 2017, set a new company record for total footage drilled in a single year. Second, we deployed our first in-house rig control system in 2018, which was developed in collaboration with Current Power, a company we acquired late in 2018. This in-house control systems makes us less dependent on third-party companies and gives us greater flexibility in developing our own software applications. The new control system has been deployed on 5 of our APEX rigs. Third, we developed a proprietary operating system for our APEX rigs that serves as a central platform for interfacing the rig control system to applications for optimizing, monitoring and automating rig equipment functions, which we have named CORTEX. Together with our PTEN+ performance center in Houston, CORTEX enhances our ability to improve drilling performance for our customers. Our first application on the CORTEX operating system is an enhanced auto driller designed to improve the on-bottom drilling performance and early field tests have been very encouraging.

Turning now to our contract drilling outlook. The sharp drop in oil prices in December resulted in some of our customers notifying of us of their intent to release rigs. Recently, with the sharp rebound in oil prices above $50, we have seen an improvement in operator sentiment and discussions with operators about putting rigs back to work is slowly increasing.

For the first quarter, we expect our rig count will average 174 rigs and average rig margin per day is expected to be roughly flat with the fourth quarter. An increase in average revenue per day during the first quarter is expected to be offset by the seasonal increase in operating costs, due in part to payroll taxes.

Turning now to pressure pumping. During the fourth quarter, we generated pressure pumping gross profit of $62.2 million on revenues of $320 million compared to a gross profit of $79.1 million on revenues of $422 million in the third quarter. This sequential decrease in both revenues and gross profit is primarily a function of lower activity levels that were driven by year-end E&P budget exhaustion. Additionally, a portion of the revenue shortfall resulted from an increasing number of customers self-sourcing their own sand. We continue to make progress in improving our pressure pumping performance, with a fourth quarter showed an increase in gross profit margin sequentially, primarily driven by increasing internal efficiency such as lower nonproductive time at the well site and an increase in average stages per day.

Turning now to our pressure pumping outlook. With the weakness in commodity prices late in the fourth quarter, operators have been delaying new completion projects, further exacerbating the already oversupplied market conditions. Pricing remains extremely competitive. As such, we have made the decision to idle spreads rather than work at unreasonably low pricing levels. We ended the fourth quarter with 20 active spreads and have idled 3 spreads early in the first quarter. For the first quarter, we expect pressure pumping revenues of approximately $245 million with a gross profit of approximately $35 million.

Turning now to directional drilling. During the fourth quarter, we generated adjusted EBITDA of $4.1 million on revenues of $56.4 million compared to adjusted EBITDA of $3.3 million on revenues of $51.6 million. Revenues increased sequentially due to higher activity levels as well as progress made to improved pricing and reduce equipment rental expense. Our directional drilling team continues to work to improve margin with newly engineered design improvements to address the increasingly challenging downhole environment of deeper wells with longer horizontal sections. For the first quarter, we expect directional drilling revenues will decrease sequentially to approximately $50 million due to a projected decrease in overall drilling activity. While gross profit is expected to be relatively flat at $6.7 million as we capture a greater amount of the job profitability by using our tools rather than third-party tools.

Turning now to our other operations, which includes our rental business, our technology businesses and our E&P business. Revenues during the fourth quarter increased sequentially to $32.3 million and the gross margin as a percentage of revenues was 33.8%. The increase in fourth quarter revenues is due in part to the acquisition of Current Power, our electrical controls and automation company. For the first quarter, we expect similar results to the fourth quarter.

With that, I will now turn the call back to Mark for his concluding remarks.

Thanks, Andy. As I suspect everyone on this call is painfully aware, oil prices fell precipitously in the fourth quarter. The magnitude and speed of the oil price decline was surprising, even to those of us who have witnessed many major fluctuations in oil prices.

During the 82 days between October 3 and December 24, we saw a decrease in WTI of almost $34 or 44%. The timing of the sharp decline no doubt impacted plans for the first quarter 2019 drilling and completion programs. While we at Patterson-UTI don't have a crystal ball about oil prices, we are encouraged by the significant rebound in oil prices. Since December 24, we've seen oil prices increase by $11.21 or approximately 26% in 44 days. The sharp reversal of the trend suggests to us that the best explanation for these changes in oil prices may be the rise in mechanistic trading in oil with its greater connection to sentiment than to fundamentals.

With oil prices now between $50 and $55, sentiment has improved. However, we suspect that some of our E&P customers will wait to see if these prices or possibly even higher prices remain in effect before solidifying their completion and drilling programs. If oil prices do move higher, we expect activity levels will improve. In the meantime, as stated above, we expect to see some softness in both drilling activity and pressure pumping, but we expect to see our super-spec rig utilization remain high around 95%. And on a positive side, the growing count of DUCs bodes well for a significant increase in completions during the second half of 2019.

For us at Patterson-UTI, we will continue to focus on the things that have made us a leader in our markets and served us well in prior periods of uncertainty. First, and most importantly, we will continue to focus on our efficient and high-quality services. We will also continue to focus on our fortress-like balance sheet. By keeping debt relatively low and not stretching the balance sheet, we are well positioned to weather whatever may come. We ended 2018 with $245 million of cash on our balance sheet and a net-debt-to-cap ratio of only 20%. Our $600 million revolver is currently undrawn and does not expire until 2023. And we also do not have any term debt maturities before October 2020.

One core tenet of Patterson-UTI is to remain flexible. We have the ability to quickly scale the business higher as activity levels expand, and when activity levels contract, we've historically been able to respond quickly and reduce our cost structure.

I'm pleased with the $181 million of cash we returned to our shareholders in 2018, including the $150 million of share repurchases. With our reduced CapEx, we expect to be substantially free cash flow positive in 2019. As we look at the current market environment, our highest capital allocation priorities are returning cash to shareholders, to debt repurchases and dividends and reserving some capital for possible debt paydown.

I'm pleased to announce today that the company declared a quarterly cash dividend on its common stock of $0.04 per share to be paid on March 21, 2019, to holders of record on March 7, 2019.

With that, we would like to both commend and thank the hard-working men and women who make up this company. We appreciate your continuing efforts.

With that operator, we'd now like to open the call for questions.

(Operator Instructions) Your first question is from Kurt Hallead with RBC.

So it appears based on the information you guys provided on an average rig count of about 174 in the first quarter that at some juncture you're going to hit about 165 rigs during the course of the first quarter. I guess my question to you is, does that kind of math jive with what your customers have told you? And then secondarily, you talked about better discussions here recently as oil prices have rebound, what kind of a bounce do you think you might get on a land drilling as you move into the second quarter?

Kurt, so where we are today with some of the notifications that we've had in terms of what operators want to do, we could still go down from where we currently are operating 175 rigs. We could still drop another 6 to 7. But we don't anticipate this going below the upper 160s. So that's where we are today in terms of rig release. But that could change as well. We've seen some change in sentiment. So we're going to see how this plays out. Not all the operators are -- finalized their plans. So I would say this is still fluid.

And then in terms of what you might expect in terms of a rebound in drilling, as you mentioned oil company's sentiment has improved with a rebound in oil price, could you give us some kind of feel and some color around that discussions? And again, if you were to handicap it, Andy, what kind of bounce could we see in the market?

It's been a huge swing in sentiment from what we saw in the second half of December to where we ended up in January. And I think the challenge for us is that operators haven't confirmed their plans. We have this range that WTI is trading between $50 and $55 a barrel right now. And I think things are going to stay relatively steady at that WTI. So we'll have to wait and see what the decisions are that some of our operators and customers are going to make.

Before taking the next question, I just want to restate what I said about our highest capital allocation priorities. They are returning cash to shareholders through share repurchases and dividends and reserving some capital for possible debt paydown.

Your next question is from Marshall Adkins with Raymond James.

Mark, I'll start by saying, yes, we appreciate return of capital on -- the investment community that I've talked to desperately wants that from all of our energy companies and you guys are one of the few that are really proactively doing it through dividends and share buybacks, so thank you for that. I want to shift to pressure pumping, Andy, if I could. You're laying down some crews here. Just out of curiosity, I mean, what's the difference in the crews you're laying down versus ones that are still working? Is it the customer base? Is it they are more efficient or pricing pressure hasn't hit those? Just give us some color about the ones that are still working. And do you anticipate any further reductions as we go into Q2?

So thanks for the question. In terms of pressure pumping that we're seeing in Q1, the softest markets for us is the Mid-Con. And that's where we're seeing the most reductions in this quarter. We're seeing it still very competitive out there on the pricing. The market is still oversupplied. And it's difficult to have much visibility past Q1 because operators haven't finalized their plans yet for the most part. But we suspect that Q1 is likely the low for 2019. So we're upbeat about 2019 relative from where we are today. But we still have to wait and see what operators finalize in terms of plans.

So it sounds like there's still going to be some pricing drift that we should model in through Q1, probably into Q2 as well? Is that a fair summary?

I would think that from our standpoint, the estimates that we've given you in terms of projections for Q1 have the majority of that in.

Okay. Last question from me. One of the things we look at is obviously fleet attrition for the industry. Do you have any sense of where that's headed? I know you all built -- added a lot of your equipment back in the '12, '13, '14 -- or '12, '13 timeframe. When does this stuff start to wear out, both for you and the industry? And just give me your sense of where you think equipment attrition -- or how relevant that's going to be going forward?

So the last year that we actually purchased equipment was in 2014. And unfortunately, some of that equipment took a holiday during the downturn. We did ramp up activity over the last couple of years. But the market is clearly oversupplied at this point based on the overall activity that's out there. We did the Seventy Seven Energy deal. And at that time, the view was that we were short pressure pumping equipment. But since we've done Seventy Seven, there's been equipment coming into the market from various other companies. And so we see current oversupply. But again, the first quarter this year in 2019 could be the low as well.

Marshall, I'd say one thing. Because of our fortress-like balance sheet, we haven't had to cannibalize any of our equipment. And one of the decisions that Patterson's taking by idling fleets is the view that says that at uneconomic pricing, we don't see the purpose of wearing out our equipment. Some of our brethren in the industry seem to have a view that says that however low the price goes, the more of the activity they would like to do. That's not our view, that's clearly not our view, and they're going to wear out their equipment and that will, in my mind, potentially help the overall market, especially if demand increases in the back half of the year as some analysts have predicted.

I think the other thing I'll add in terms of industry attrition, it's actually hard for us to get a view of what the overall industry attrition is based on the oversupply in the market. And when the market's tighter, it's easier to know what some of the competitors are doing. But where we are in the market today, it's a little bit tougher to know.

And your next question comes from James Wicklund of Crédit Suisse.

A little bit -- good color, by the way. A little bit of a follow-up on Marshall's point. We are currently oversupplied in the pressure pumping equipment. In the cycles that I've seen, we lose pricing pretty quickly, and it takes a little bit longer to gain it back. What are your ambitions, if you would, Andy -- and I know that none of us have a crystal ball, but can you give us an idea of where you would expect the year to end, exit rate margin, if you would, for pressure pumping just on a historical basis? Will we get back to mid-'18 pricing? Can you talk a little bit about what you expect to see in terms of the timing and magnitude of pressure pumping pricing through 2019?

Jim, I think that to best answer to that question, I have to qualify on where WTI trades. And with a $50 to $55 range on WTI, Q1 could be a bottom in terms of activity, but it will be more challenging to move pricing until WTI moves higher and overall activity and utilization pushes up from where we are today. So internally, in what we're doing with our division, Universal Pressure Pumping, we continue to make progress on efficiency. Our teams are doing a great job out there. And I'd like to commend them for their results in the fourth quarter. And we'll continue to work on that and continue to try to get ourselves up into that top quartile.

Okay. And my follow-up, if I could. There is at least 13 pressure pumping companies I can name off fingers and toes real quick. Mark, you make the point that not all of them have the capital discipline that you do. You could put 3 of these guys together and they'd be the size of Halliburton, and that kind of market consolidation sure would be positive. I'm not asking if you'll be the consolidator, unless you'd like to tell us. But do you really see the pressure pumping industry overall consolidating over the next couple of years? Or will egos and differentials get in the way?

Marshall, it strikes me that -- pardon me, Jim.

I'm Jim. Marshall was before.

Sorry, Jim. It strikes me that ultimately one can see consolidation, but consolidation never happens at the very bottom of cycles. It tends to happen as people come out of bottoms and, in effect, stock prices and other things recover. That's when deals seem, in our mind, most likely to occur. So if you asked me...

I would agree. But Andy said he thought that the first quarter could very well be the bottom. So doesn't that mean that we will start consolidating through '19?

It takes a little while as you know, Jim, for that to start to become evident to the players. So I think it will occur. Is the industry incredibly fragmented? Yes. Do I find that surprising because as you and I both know, 20-plus years ago, this was an industry in which 3 players had 90%. And so it was incredibly consolidated. Now that the industry is incredibly fragmented, it's just amazingly different from what it used to be. Do I think that -- sort of interestingly, there's almost 2 tracks you can well envision.

One is, WTI increases, activity increases, everybody gets healthier and then there's a question about people's ability to put together businesses, get over social issues, et cetera, et cetera. That's one certain set of facts. The other is that it stays about this level, pricing remains brutal and we'll see just who can survive brutal pricing. And that's the second possibility and that may drive activity in a different kind of way. So those are the 2 possibilities that frankly I foresee. And I can't tell you because I can't predict oil prices, exactly which it's going to be, but I can tell you that either way, Patterson is going to be fine, irrespective of which direction we take.

Jim, just to follow on Mark's comments, we've been in drilling and pressure pumping both for a long time. And I have expressed the sentiments at the last few conferences we've been at as well. Just making a macro call, I think it's highly likely you do get consolidation, but it takes time. If you roll back the clock 12 to 15 years, we had the reverse. Drilling was not relatively consolidated and pressure pumping was. And I think markets are efficient and over time they work themselves out.

And your next question comes from Sasha Sanwal from UBS.

And so for the first question, just to kind of follow up on one of the earlier questions just about the U.S. line rig count. So if we think about this typical kind of notice period that you E&Ps have to give you guys, I just want to get more color on what's kind of embedded into the average Q1 rig count guidance of 174, right? So are you essentially just looking at rig releases that you have in hand today? Or are you kind of factoring in additional release that might come through in the next kind of month?

We're giving you our best visibility for the quarter. And we think that our rig count could come down by another 6 or 7 rigs, based on what we know. Operators could also change their mind before that happens. But that's about where we are from where our rig count is today, not from an average but where we're -- on our website, our rig count's at 175 today.

Great, that's helpful. And just on pumping, could we just get some incremental kind of color on what the Q4 utilization rate was and then just kind of how that feeds through to Q1 given that we're going to be stacking 3 of the fleets?

Yes. I'd say our overall utilization in the fourth quarter for the spreads that we're working is relatively high with very little white space in the calendar, and we were very efficient. As we go into Q1, because of notifications that happened in December, with the gyrations in WTI that we had, we are seeing a softening in the first quarter. And we're seeing increased white space for the spreads that we plan to operate in the first quarter as well. But I think that, that could improve as we get into the second quarter and maybe further into the year.

Your next question comes from Judson Bailey of Wells Fargo.

Andy, I wanted to get your thoughts here of your '17 crews. If oil stays, let's say, $55 or averages that for the rest of the year, how do you think about your active crew count. Do you think it's more likely you stay at that level? Or would you envision a scenario where you could put 1 or 2 spreads back to work? And if you did, what kind of economics would you need to see on like, I don't know, EBITDA per fleet? Or how would you think about bringing something off the fence given that you just stacked a few crews. If you could give us your thoughts on that, that would be great.

Yes, given the premise of $55 a barrel, I think it is possible that we get put 1 or 2 crews out sometime in 2019. I think it's possible that at $55 a barrel that we see pricing that makes sense for us. Remember, some of these decisions that are being made that are affecting us in the first quarter, were made when oil was below $50 a barrel. So at $55, could we put out 1 or 2 spreads with reasonable pricing? I think we could. I think you also see us continue to improve our internal efficiencies in 2019 and slowly improve our profitability internally as well.

Okay. And if you were to reactivate something, how would you think -- or how should we think about kind of the economic threshold or how you think about what you need from a contracting standpoint in order to do that?

I don't think anything's changed in terms of the way we view a reactivation. We have set ourselves up so that we still are carrying a little bit of the headcount required to reactivate when necessary in terms of experience, and our equipment is in good condition. We continue to fund maintenance capital. So activating equipment is fairly straightforward for us. And it'll be the same premise that we used in '17, '18. Does it -- does the pricing make sense and does the margin make sense in the basin we're working in.

Okay. And then my follow-up is, just on the super-spec upgrades, it sounds like not surprisingly, discussions have cooled off quite a bit but maybe if you could give any color you may be having with customers around a term contract. Is that completely off the table? Or do you still think a couple could potentially happen this year even though you do have super-spec rigs now idle. I would just appreciate any thoughts there.

I think we'll have to wait and see. Again, we're still waiting on the majority of our customers, the E&Ps to finalize their budgets and make decisions on what they want to do in 2019. And oil prices were trading where they were in November, we would've expected some more major upgrades than what we are currently planning on right now. But because of the gyrations in December and some of the decisions that were made in December, some of those discussions have cooled a bit. But I'm still relatively upbeat. Remember, utilization and super-spec rigs is in the mid-90s percentile right now. That's still tight. And so that still supports pricing to some extent. And we'll just have to wait and see what decisions some of the E&Ps make.

Your next question comes from Mike Urban of Seaport Global.

Did -- I want to follow up a little bit on that last question. I completely understand there's not a lot of clarity out there just given the budgets haven't been finalized. So would you say that there is interest from your customers in additional upgrades and those discussions are out there but they just aren't willing to offer term at this point? Or is there just they have just kind of dried up at this point?

I think the challenge is the discussions have gone quiet just because of the timing and what's happening with commodity prices and operators still trying to finalize 2019 after going through the swings in commodity prices. So when we get back into the discussions, I think term contracts are back on the table. We're just not in those discussions right now. So we haven't budgeted for more than the 1 major upgrade that we have in addition to deliver.

Okay. And then apologies if I missed this or kind of wrote this down incorrectly. On the CapEx budget for drilling, it does look like there is a small amount of growth CapEx still in there. Is there an assumption at some point that upgrade discussions do resume? Or are those for kind of just other miscellaneous capital items?

Yes, we talked about major upgrades and we talked about other smaller market upgrades, it's very likely that we'll be doing some of the smaller market upgrades during 2019, whether it's high-capacity drill pipe or adding a generator or a pump or a walking system. And so those are still in the budget as well. But those come with an increase in the contract term when we do that.

Your next question comes from Scott Gruber of Citigroup.

Andy, you continue to make good strides here in enhancing the drilling offering, expanding the revenue channels, you have a new operating system. I like the brand name. And now you're developing apps to go on top of that. But as we think about the next 3, 4 years, what else would you like to add or develop to really get where you what you want to be from an integrated offering in drilling and ancillary services around the rig?

I think in terms of the drilling rig and what the drilling rig can offer to operators, I think we're just starting this journey of enhancing the offerings that we have today through software. And by adding our CORTEX operating system and the engineering work that we're doing on software applications to layer in on top of that, it increases the performance and the efficiency of the current hardware offering we have out there. That's positive. We're not talking about large capital investment and changes in hardware. We're talking about capital investments in the engineering software to make the current offering perform better. And we certainly intend to monetize that.

That's a huge benefit for our customers when we do that. And it differentiates us from the competitors at the same time. And I think it's a real opportunity to improve performance for the operators and for us to share in that improved performance at the same time. I think that we're just at the start of that. So I think that for the next several years, you're going to see more in that area and there's more we can do in terms of those software applications to improve performance.

At least one of your peers is talking about new contract structures to help better capture the economics and technology that they are throwing on the rig. As you guys dig deeper into the development of the software and the apps, are you contemplating new contract structures to better capture the value?

I think that we're very intent on capturing the value. I'm not sure that includes a complete change in the contract structure, but it certainly includes us negotiating what that value-add is for the operator. But -- and the value-add on improving performance for an operator is not just about saving days and saving dollars, it's about bringing production forward and that's a huge value for the operator.

Got you. And then just one quick follow up. Where are you at in terms of internalizing the tool construction within directional?

We've always had our own equipment within our directional drilling business. We had some challenges with third-party deliveries during 2018. We have most of that behind us. We've engineered some new products on downhole tools as well to enhance the current offering. And so we're moving away from having to use third-party equipment for those reasons.

And your next question comes from Dan Boyd of BMO Capital Markets.

I want to come back to the pressure pumping strategy because I'm sure you like many of us are frustrated with the market and the stock really finding little value probably to that segment or at least when we do the sum of the parts. So I think you made a good point earlier on land rigs weren't consolidated, they became consolidated. I would say a lot of that consolidation was really because of the obsolescence of older, less efficient rigs. And we've seen a lot more bifurcation in pressure pumping performance over the past years between the top quartile and the bottom quartile, a little similar to what we've seen previously in land drilling between mechanical and AC or super-spec rigs. So kind of the -- my question is, have you been able to identify the drivers of the top quartile performance versus the bottom quartile performance in pumping? Is it an equipment issue, an infrastructure issue, a process issue? And do you see a -- is there a strategy in place and a timeline to turn things around?

We've been adamant that we intend to be top quartile in pressure pumping. We've been in this business since 1980. It's not new for us. If you look at how we performed a few years ago, we were in the top quartile. And there's no reason we can't be back in the top quartile. So we're working on those things, you see the internal improvements that we're doing and results like we had in Q4. The market will mask some of the improvements that we're making internally at the same time, but we'll continue to improve.

Is there anything specific though? So do you think your equipment is right in line with everyone else's? It's more of a just aligning with the right customers and a process which will just take time?

There's absolutely nothing wrong with our equipment. Our equipment is top-notch. We continue to fund maintenance CapEx. And so there's no issue with our equipment. Our equipment stands side-by-side with the best companies out there. I think that when you look at some of the competitors that we have that have been purchasing new equipment over the last couple of years, I'm not sure that their numbers can stand over the next few years, if that makes sense. So I think their maintenance OpEx costs will continue to move up, but we will continue to improve our performance at the same time.

And your next question comes from Chase Mulvehill of Bank of America.

First question. I'll stick on pressure pumping and just kind of back in to some numbers. It looks like that you expect annualized EBITDA per fleet or gross profit per fleet to kind of decline about $4 million quarter-over-quarter. Can you talk about the sequential decline and how much of that is kind of related to utilization and how much of that is pricing?

So it's a mix of several things. It's going to be fixed cost absorption as we move down to a lower number of spreads from Q4 to Q1. Some of that is pricing as well, but also some of that is an increase in white space in the calendar. And that's why there is a good chance that Q1 makes for a bottom as we move into Q2.

Okay. And then on CapEx. If I heard you right, I think you said $145 million of maintenance CapEx for drilling. Just kind of based on a plausible kind of rig count, that seems pretty high. On our math, it's probably about $50 million higher than we would've thought just applying $1,500 a day on maintenance. Is maintenance CapEx just taken a step higher structurally? And if so, kind of what should we think about from a maintenance CapEx on a per day basis?

When we look at the overall maintenance on the rigs that we're providing, with the super-spec rate, with the additional equipment and hardware, with the deeper wells and the longer laterals and the improved performance, maintenance CapEx has moved up a bit. We're probably closer to the range of $2,000 per operating day for a drilling rig. But if I look at a top peer in the space, I think we're right at the same level, so I don't see that as a negative for us.

Okay. And the $20 million, did I hear that you had corporate CapEx of about $20 million?

That's correct.

Okay. What actually is that? Because I don't think -- that's pretty higher than kind of what you been spending in the past?

Yes. There are number of things that go into that. I mean, some -- a little bit of IT upgrades and a myriad of other miscellaneous items.

We've held it really tight in the past few years to get to our target of free cash flow. After CapEx last year and returning dollars to shareholders, we need to adjust that this year and catch up on a few things.

Nothing to do with international expansion or anything?

No.

No.

Okay. If I can sneak one in real quickly on -- we're getting a lot of questions on this. Leading edge dayrates, what are you seeing for leading edge super-spec? Are you still kind of in the mid-20s? And then what about some of your non-super-spec rigs?

I think leading edge on dayrates for super-spec rigs, is hard to really determine right now just because of what's happened at the end of December and coming into the first part of the first quarter. But just to remind you, with the utilization in the mid-90s percentile level right now, the market's still tight. I think that supports dayrates.

You're next question comes from Taylor Zurcher of Tudor, Pickering, Holt.

On the drilling side, if you think about -- I think your rig count peaked out in the mid-180s. And it sounds like it's going to go to the high-160s, at least, in the next couple months. Within that mix of rig count reductions and expected rig count reductions over the next months, can you frame for us how many would be super-spec rigs and how many would be some of your legacy FCR rigs?

We've got a mix of super-spec and FCRs. But I don't see a big drop in overall super-spec utilization.

Okay, perfect. And then on the pressure pumping side. It's good to see progress on some of the internal efficiency improvements that you guys are working on, the press release noted that your average stage of frack per day per pumping day is up sequentially. Can you give us some more color as to where that metric stand today? I know it probably varies basin by basin, but where does that metric stand today and with the things you're working on, the customers you're aligned with, how much more room to run do you have from a stages pump per perspective moving forward, maybe over the course of 2019?

Yes, we don't get into too many specifics on that for competitive advantages. But I think there is still room for improvement, not just in stages per day but in managing our cost as well. So it's multiple fronts that we're working on in terms of improving overall financial performance.

Your next question comes from Brad Handler of Jefferies.

I guess maybe I'll come back to the dayrate question just to try it in a slightly different way. But presumably, you have had some contracts roll off over the last couple of months, and they were priced -- perhaps they had been priced a year ago or 6, 8 months ago. Have you been able to push those rates higher as you roll them on to new work?

So if you look at what our average revenue per day is doing, you're seeing the effect of term contracts that may have been signed 6 months, 1 year ago, 1.5 ago rolling into higher pricing, and that's what you're seeing as we go into Q1, on average.

Okay. Yes, I'm just trying to -- Okay, well, I'll move on. On pumping, I'm trying to get a little bit of perspective. If -- I guess once you had closed the Seventy Seven Energy, if I recall your horsepower was north of 1.5 million, which would've suggested something like a capacity of 30 fleets. So you're currently running at 17. And obviously, you're hopeful that there are some prospects to put a couple back again. But can you talk a little bit about what level of capability you're hoping to sustain? What sort of a reasonable fleet count from a capacity standpoint that you want? And if the number is much smaller than the 30, then does that offer some pretty meaningful cost opportunities for you if you say "well, okay, structurally, it looks like it's going to be a smaller business for a while and that gives us a chance to create some efficiencies -- more structural efficiencies?"

So we were at 1.5 million-horsepower after the Seventy Seven deal. And if you look at how many spreads we were operating last year, we got up as high as 25. The challenge in the market is with the oversupply. We would've pushed higher than 25 if the market had allowed us to. With us being down at 17, we're going to have to manage the scale of the business at the same time. And so it's one of the attributes of Patterson-UTI. That's one of the ways we run the business. We have to scale to stay in line with the activity levels that we have. But it doesn't mean we can't scale back up. But I think we are in a good position if the market allows us at reasonable pricing to put more spreads out. Again, we were up to 25 the year before. Structurally, overall though, the market was oversupplied for most of the '18 and it's oversupplied where we are today in 2019. So we're going to have to see some improvements in drilling activities overall driven by WTI in order to push this back up to 25 spreads or higher.

Right. Right. That's helpful. If I may just one last one. On the directional business, maybe you could help me make sure my math right. But we've been trying to -- assuming you're trying to get to the point where it's free cash flow positive. If your EBITDA after G&A was $4 million this coming quarter and there's some risk to that, at least in the beginning of part of 2019, so $4 million in 4Q '18. You're still spending something close to $6 million a quarter in CapEx. When can that get to free cash flow neutral/positive? What do you need to do? Are you still investing in CapEx in a way that it can fall off in 2020 or something along those lines? But some color around that would be helpful.

Yes. I think that, that business has the opportunity to improve margins through 2019. With the drilling rig -- with the overall industry drilling rig slowdown that we're seeing in Q1, they are affected by that. So we'll have to wait and see how plans from operators firm up. But I think it will continue to improve our margins through 2019 and cover the cost of CapEx and generate free cash flow.

And your next question comes from Tommy Moll of Stephens.

So it's understandable that your visibility on leading-edge dayrates for super-spec is limited just given I imagine the conversations like you said on new contracts have been put on pause for the time being. But how much confidence do you have both for Patterson as well as for the industry that when those conversations do pick up again, we will continue to see price discipline in what's been one of the better markets fundamentally across the oilfield landscape lately?

I think this sector of the industry, contract drilling and super-spec rigs has a great history of discipline. You saw discipline in 2015 and '16 as we went into the worst downturn in the history of counting drilling rigs in the U.S. where utilization overall dropped 70%. But those businesses stayed cash flow positive because there was relative discipline. You saw relative discipline as we came out of that downturn in '17 and '18. And you saw pricing being pushed up fairly quick. And I don't think anything changes. I think you'll continue to see relative discipline. And in super-spec rig, again, utilization is in the mid-90 percentile. There is no reason for there to be a pricing challenge right now.

Good to hear. And then as one follow up on the drilling CapEx. Just bridging between the $145 million for maintenance and the $225 million overall. You called out earlier that a lot of that is for some small upgrades. Are those for rigs you anticipate put into work throughout the year? or rigs that are already working where you anticipate needing to upgrade them in the middle of the year? Just help us understand the moving pieces there and potentially how many rigs that would apply to.

So for the most part because we are operating so many rigs today, 175 today, these are small market upgrades that would happen on existing drilling rigs. Like I said, it could be higher capacity, high torque, double shoulder connection drill pipe. It could be an addition of a comp and a generator. It would be addition of other equipment at the well site. And these are fast payback items. So these are just small upgrades. We get better terms on the rig when we do this and it's a quick payback.

Your next question comes from Jeffrey Campbell of Tuohy Brothers.

Do you intend to retrofit this in-house power system that you referenced on the call today throughout the super-spec fleet? And if so, how quickly would this rollout? And I guess what I'm trying to understand is, is this ultimately accretive to replace third-party equipment with this in-house offering? Or is this more about having surety of supply, surety of incremental supply?

It's -- in the end, it's really about the performance enhancements that we can put on a drilling rig and capturing the value of that performance with our customers. There's no rush to move this out to drilling rigs any faster than the market can uptake. In terms of the software application, the enhanced auto drillers, for instance, it's in field test today. In terms of the CORTEX operating system, we'll move that on rigs where we can extract value for that. And so we're very focused on margin improvements and capturing value for technology. And we'll do it where it make sense and where we can reach an agreement with the customer.

Okay. Great. I appreciate that. And my other question was, you mentioned you the growing DUC inventory, possible upside to completions in the second half of '19. I was wondering, is that a view that's already embedded in the current spreads that are working? Or could that upside put idle crews back to work?

So it could be with current spreads and take white space out of the calendar. It could be with additional spreads depending on how the market plays out in 2019. But very clear that at the end of 2018, we had a slowdown in overall completions in the industry as we had E&P budget exhaustion, and we saw an increase in the drilling activity. So you had an acceleration in the DUC count towards the end of 2018 that in some point in 2019, we'll work through.

And your next question comes from Ken Sill of SunTrust.

I guess, more of a philosophical question. You guys look at deploying capital in the Drilling business, which is consolidated, longer asset lives, get contract terms versus pressure pumping, which is more volatile and has shorter asset lives. Is your threshold or return that you're required to put money into those different assets the same? Or do you need higher returns for one versus the other?

Ken, we expect higher returns for money that we spend in pressure pumping because of all things you just described.

Okay. That's a good answer. And then on the DUC count, I mean, this is one I find curious because -- do you have customers out there that are actually drilling and not completing wells on a -- in a big way?

We have customers towards the end of Q4 who increased their drilling activity and slowed their completion activity to stay within their budget.

And that was in the Q4? Was that...

Margins...

Yes, specific to any region more versus other?

No. It was, I would say, in general across the U.S.

Yes. And then you guys noted that the activity has been soft in the -- basically, up in Oklahoma in the SCOOP STACK, the Anadarko basin, which is where the biggest drop in drilling has been. Do you guys think this has anything to do with well economics? Or is it just -- there's just a lot of smaller customers out there that are playing things close to the vest right now.

I'm probably not the best person to speak to what's happening up there other than in 2017, there's a lot of discussion about the SCOOP and the STACK and how the economics could be similar to what we have in the Permian in Texas. And it just hasn't played out. And if you look at what happened in 2018, we just didn't see a big ramp up in drilling activity. We've seen a slowdown now in drilling activity in the Mid-Con and now we have a subsequent slowdown in services activity in the Mid-Con as well. So that -- from our view, it just hasn't materialized as some of the discussions lead to from 2017.

Your next question comes from Greg Gendron of Wolfe Research.

Just one quick one from me. Even in the volatile environment spending, it would seem that the Permian will drive the majority of the spending growth. So if you look at the rig market there from a competitive standpoint, are your customers asking for specific specs in the rigs? Appreciating that not all super-spec rigs are created equal? Or is there a pretty high substitutability between super-specs and perhaps Tier 2 rigs. And then I guess, how does the software directional drilling upsell play into the competitive leverage in the Permian specifically?

By nature of the definition of a super-spec rig where you're talking about a rig load capacity of 750,000 pounds plus, horsepower rating of 1,500 horsepower or greater, walking systems, high-pressure circulating systems, it makes that class of rigs relatively similar. But it all gets down to execution. So the hardware could be similar but you're going to see differences in execution. We think that we are one of the best performing drilling contractors out there. And now we want to up the ante by adding on software enhancements to improve what we're doing. And we want to be able to capture the value for that as well. So we think that while mechanically the rigs look similar on paper, there is differentiation in execution and the processes that we run. And we think there's further differentiation by enhancing that offering with software capabilities that take discrete processes on rigs and start to automate those processes.

Your next question comes from Colin Davies of Bernstein research.

I got a question on the very proactive decision to lay down spreads on the pressure pumping side. It's good to see some leadership there around take -- increased level of discipline in the sector. But the obvious implication is that there is an impact on market share. Could you perhaps comment on that to the extent to which you have been able to minimize that by consolidation of activity on to the spreads that are working? And then perhaps some forward commentary on how far are you prepared to have customer relationships perhaps harmed by that transition in market share?

So one of the things that I'll point out, this is a history of the company, we're a very margin focused company and there's really no point in us chasing market share, especially in the pressure pumping side of the business with the number of various companies that are out there. It's more important to try to focus on margin and protect the margin. So market share in pressure pumping is not a metric we worry about. We try to stay focused on providing the best earnings results from that business. And reducing the number of spreads is a strategic decision to try to improve our overall business performance and help shore up the markets. But that's -- from a pricing and margin standpoint if that can help. But granted, we understand there's also a large number of competitors out there and we're looking forward to seeing some of our competitors move in the same direction.

Yes. I mean -- I guess the flip side of this consortium -- the idea of trying to get more discipline into the sector and certainly that pressure is now coming from the investment community as well. Is it -- how are the customers reacting to those conversations? Because so far in that particular part of the industry, it seems that the customers have had it pretty good, they've been able to push on price pretty aggressively. With investor pressure on the services side, is it changing that dynamic at all for the positive?

So there is still an oversupply in the market as we see it in the first quarter. There's still competitive -- very competitive pricing that's out there. And I think that operators with their overall slowdown in completion activity in the fourth quarter and having not really ramped that up yet benefit from that pricing competitiveness today. We'll just have to see how that works out through the rest of 2019.

I would just add one thing. There's different companies out there, some of which are newly formed private equity backed entities that have not got 30-year-kind-of history -- that 30-plus year history that Patterson-UTI has in this industry. So we sort of play the long game. Some of these folks in affect have only one game they can play, which is the short game. That's why that we think that they're perhaps more willing to accept uneconomic market pricing and wear out their equipment more quickly than we are.

And our final question comes from John Watson of Simmons.

Just a quick one. We continue to hear anecdotes of fluid ends lasting longer and costing less. Could you quantify what component of the $120 million of pressure pumping CapEx is allocated for fluid ends?

Yes. We haven't really called that out in terms of the fluid end spend in our CapEx budget. But I do concur that our spend on fluid ends improved in 2018 in terms of we spent less as we worked our way through the year. I think there's some things we can do in 2019 to reduce fluid end spend per hour of operating time as we work our way through 2019 as well.

And we have no further questions in the queue. So I'll turn the call back over to Mark Siegel for closing remarks.

I just would like to thank everyone for participating in our Patterson-UTI conference call -- fourth quarter 2018, and look forward to speaking with you on our call for first quarter 2019. Thanks, everybody.

And this does conclude today's conference call. You may now disconnect.