Patterson-UTI Energy, Inc. (PTEN) Q4 2018 Earnings Report, Transcript and Summary

Good morning. My name is Adam, and I will be your conference operator today. At this time, I’d like to welcome everyone to the Patterson-UTI Energy, Fourth Quarter Earnings Conference Call. All lines have been placed on mute to prevent any background noise. And after the speakers’ remarks, there will be a question-and-answer session [Operator Instructions]. Thank you. Mike Drickamer, Vice President of Investor Relations, you may begin your conference.

Thank you, Adam. 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 fourth quarter and full 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 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 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 for what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement. The company’s SEC filing 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 31st. 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 $211 million of noncash pre-tax goodwill 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 the quantitative impairment assessment of our goodwill as of December 31, 2018, due to the decline of our stock price and the deterioration accrual prices in the fourth quarter of 2018. In completing the assessment, we recognized a non-cash charge for the impairment all of the goodwill in our pressure pumping and directional drilling reporting units. Consolidated adjusted EBITDA for the fourth quarter was $213 million, which were up 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 return 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 expensed 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 Rental, 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 five 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 $2020 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 rigs 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 at an average of 78 rigs operating under term contracts during 2019. During 2018, we completed 14 major rig upgrades and we have completed one major rig upgrade this year. We have one additional major rig upgrade to be delivered in the first quarter of 2019. Within in 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 required term contracts for 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-90% range. In addition to the advancements made in the super-spec rig market, I want to commend our team for the operation achievements and 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 drill 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 owned software applications. The new control system has been deployed on five of our APEX rigs. Third, we developed a proprietary operating system for our APEX rigs that serves at the 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 Plus Performance Center in Houston, CORTEX enhances our ability to improve drilling performance for our customers. Our first applications 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 us of their intent to release rigs. Recently with a 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 favorable 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 was 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 where the fourth quarter showed an increase in gross profit margin sequentially, primarily driven by increasing internal efficiencies such as low non-productive 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 three 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 for newly reengineered design improvements to address the increasingly challenging downfall 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 captured 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 $33.3 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 drop precipitously in the fourth quarter. The magnitude and speed of the oil price decline was surprising even for those of us who have witnessed many major fluctuations in oil prices. During the 82 days between October 3rd and December 24th, 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 rebound in oil prices. Since December 24th, we've seen oil prices increase by $11.21 or approximately 26% in 44 days. The sharp reversal of the trend, suggest to us that the best explanation for these changes in oil prices may be the rise in mechanistic trading in oil with this greater connection to settlement and the 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 in 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 rigs utilization remain high around at 95%. And on a positive side, the growing count of DUCs bodes well for significant increase in completions during the second half of 2019. For us at Patterson-UTI, we will continue to focus on things that 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 whether 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 tenant 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 reduced our cost structure. I am 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 through debt repurchases and dividends and reserving some capital for possible debt paydown. I am 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 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. Your line is open.

Hi. Good morning.

Hi. Good morning.

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 were in about 165 rigs during the course of the first quarter. I guess my question to you is, is that kind of math jibe 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?

Hey, Kurt. Good morning. 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 can still drop another six to seven. 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 and so we're just going to have to see how this plays out. Not all the operators are finalized their plans and 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.

Great. Appreciate that color. I'll turn it over.

Before taking the next question I just want to restate what I said about highest capital allocation priorities. They're returning cash to shareholders through share repurchases and dividends and reserving some capital for possible debt pay down. Thanks.

Your next quarter is from Marshall Adkins with Raymond James. Your line is open.

So, Mark I guess I'll start by saying, yes, we appreciate that return of capital. All 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 really proactively doing it through dividends and share buybacks. So, thank you for that. I'm going 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 the 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, good morning. Thanks for the question. In terms of pressure pumping what 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 a much visibility positive 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 for me. One of the things we looked at is obviously fleet attrition for the industry. Do you have any sense of where that's headed? And I think you all built -- added lot of your equipment back in the trial 2012, 2013, 2014 or 2012, 2013 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, 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 markets 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 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 and 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 equipments. And one of the decisions that Patterson's taken by idling fleets the view that says that add 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 growth goes, more activity they would like to do, that's not our view. It’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 on what that overall industry attrition is based on the oversupply in the market. When the markets 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.

Got it. Thanks, guys.

And your next question comes from James Wicklund of Credit Suisse. James, your line is open.

Hi, guys. A little bit -- good quarter by the way. A little bit of follow-up on Marshall's point, we are currently oversupplied in the pressure pumping equipment. And the cycles that I've seen, we lose pricing pretty quickly. And that takes a little bit longer to gain it back. What our your ambitions if you would, Andy and I know 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 where we get back to mid-2018 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?

Hey, Jim, good morning. I think that to best answer 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 in overall activity and utilization pushes up from where we are today. So, internally and 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's at least 13 pressure pumping companies I can name of 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 three of these guys together and that'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 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 we're going to see consolidation. But consolidation never happens at the very bottom of cycles.

Right.

It tends to happen as people come out of bottoms and in effect, stock prices and other things recover. That's when deals seems, in our mind, most likely to occur. So if you asked me...

I would agree. But Andy said, he thought that the first quarter may very well be the bottom. So doesn’t that mean that we'll start consolidating through 2019?

Well, it takes a little while, as you know, Jim, for that historically to become evidence of 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 three players had 90%.

Yes.

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 – just sort of interestingly, there's sort of almost two tracks you can well envision. One is, WTI increases, activity increases, everybody gets healthier. And then, then there's a question about people's ability to, in effect, put together businesses, get over social issues, et cetera, et cetera. That's one sort of 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 other the two possibilities that frankly I foresee. And I can't tell you, because I can't oil prices, exactly which it's going to be, but I can tell you that either way Patterson's going to be fine irrespective of which direction we'd take.

Jim, just to follow on Mark's comments, we've been in drilling and pressure pumping, both for the long time. And I've expressed these 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.

Gentlemen, thank you very much for the perspective. I appreciate it. Thank you.

And your next question comes from Sasha Sanwal from UBS. Sasha, your line is open.

Thank you guys and good morning.

Good morning.

Yes. And so for the question, just to kind of follow up on one of your earlier questions, just about the U.S. line rig count. So if we think about the typical kind of notice periods 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 you're essentially just looking at rig releases that you have in hand today? Or you're kind of factoring in addition releases 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 six or seven 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 is 175 today.

Great, that's helpful. And just one pumping, can 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 we're going to be stacking three of the fleets?

Yes, I'd say our overall utilization in the fourth quarter for the spreads that we're working was relatively high with very little white space in the calendar and we're very efficient. As we go into Q1 because of notifications that happened to 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.

All right. Thanks. That's it from me guys. I'll turn it over.

Your next question comes from Jud Bailey of Wells Fargo. Jud, your line is open.

Thanks. Good morning. Andy wanted to get your thoughts -- your 2017 crews. If oil stays let's say $55 or average of 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 one or two spreads back to work? And if you did, what kind of economics would you need to see on like the 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 maybe 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 one or two crews out sometime in 2019. I think it's possible that a $55 a barrel that we see pricing that make 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 one or two 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 would think about what you need from a contracting standpoint in order to do that?

I don't think anything has change in terms of the way we view a reactivation. We've 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 2017, 2018. Does it -- does the pricing make sense and does the margin make sense in basin we're working in.

Okay. Thanks for that. 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 do you have super-spec rigs now idle? 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, E&Ps to finalize their budgets and make decisions on what they want to do in 2019. In oil prices, we’re trading where they were in November. We would have expected some more major upgrades and what we’re currently planning on right now. But because of the gyration 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.

Okay, great. Appreciate the color. I’ll turn it back.

Your next question comes from Mike Urban of Seaport Global. Mike, your line is now open.

Thanks. Good morning. 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 out there that they just don't want to offer term at this point? Or is there just that kind of dried up at this point?

I think the challenges, the discussions have gone quite 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 those discussions, I think term contracts will be back on the table. We're just not in those discussions right now. So we haven't budgeted for more than the one major upgrade that we have in addition to deliver.

Okay. And then apologies if I missed this or wrote this down incorrectly. On the CapEx budget for drilling, it does looks like there is a small amount of growth CapEx still in there. Is there an assumption that some point in the year that upgrade discussions do resume or those for 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 increasing the contract term when we do that.

Got you. Okay, that’s all for me. Thank you.

Your next question comes from Scott Gruber of Citigroup. Scott, your line is now open.

Yes, good morning.

Hey, Scott.

Andy, you continue to make the strategy of enhancing the drilling operating, expanding the revenue channels. You guys have been operating systems. I like the brand name, and now you're developing apps on top of that. But as we think about the next three, four years what else would you like to add or develop to really get where you want to be from the integrated offering in drilling in the 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, the current hardware offering that 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 differentiates us from the competitors at the same time. And so, I think, it's a real opportunity to improve performance for the operators and for us to sharing improve 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.

And then, at least one of your peers is talking about new contract structures to help better capture the economics and the technology that they're throwing on the rig. And as you guys get 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 completely change in the contract structure. But it certainly includes us negotiating what that value add is for the operator. But in 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 you're at in terms of internalizing the tool constructing 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.

Got it. Thank you.

Thanks.

And your next question comes from Dan Boyd of BMO Capital Markets. Dan, your line is open.

Hi. Thanks guys. 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 some of the part. So, I think you made a good point earlier on, planted rigs weren’t consolidated, they became consolidated. And 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 of bifurcation in pressure pumping performance over the past years, between the top quartile and the bottom quartile, maybe a little similar to what we've seen previously in land drilling between mechanical and AC or super-spec rigs. So, kind of, 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 in the timeline to turn things around?

We've been adamant that we intend to be a 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 are 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? Is that – so you think your equipment is right in line with everything else's. So it's more of a just aligning with the right customers and a process issues to 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 make sense. So, I think their maintenance OpEx cost will continue to move up, but we'll continue to improve our performance at the same time.

Okay. Thanks.

And your next question comes from Chase Mulvehill of Bank of America. Chase, your line is open.

Hey, good morning. I guess first question I'll stick on pressure pumping and just kind of backing into 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 increasing 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 would've thought just been applying $1,500 per 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 rig, 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 I look at our 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 is a number of things that go into that. I mean some facility, little bit of IT upgrades, and other miscellaneous items.

Well, we 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. So, I'll squeeze one in real quickly on -- I get -- I'm 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 and I think that’s supports dayrates.

Okay, all right. Thanks, Andy. I’ll turn it back over.

Your next question comes from Taylor Zurcher of Tudor, Pickering, Holt. Taylor, your line is open.

Thank you. Good morning, guys.

Good morning.

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 of those would be super-spec rigs and how many of it would be some of your legacy SCR rigs?

We've got a mix of super-spec and SCRs. 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 improvement things that you guys are working on. The press release noted that your average stages frac per day for pumping day were up sequentially. Can you give us some more color as to where that metric stands today. I know it probably varies basin by basin, but where does that metric stand today and with the things you're working on and the customers you're lining with, how much more room to run, do you have from stages pumped per day 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.

Okay, great. That’s it for me.

Your next question comes from Brad Handler of Jefferies. Brad, your line is open.

Thanks. Good morning, guys.

Good morning, Brad.

Let see, I guess maybe I'll come back to the dayrate question just to try a slightly different way. But presumably you've had some contract roll off over the last couple of months and they were priced -- perhaps they have been priced a year ago or six to eight 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 six month, year ago, one and a half year ago rolling into higher pricing and that's what you're seeing as we go into Q1.

Right. Understood.

On average.

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 have close a Seventy Seven Energy, if I recall your horsepower was north of $1.5 million, which would have suggested something like capacity of 30 fleets. So you're currently running at 17. And, obviously, you're hopeful that there’s some prospect to put a couple back again. But can you talk a little bit about what level of capability you are 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 then that gives us some chance to – I guess, that’s a chance to create some inefficiencies, 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. It'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're 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 2018 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 WTI in order to push this back up to 25 spreads or higher.

Right, right. Okay. That's helpful. And If I may, just one last one. On the directional business, maybe you can help me make sure my math is 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 2018. You're still spending something close to $6 million a quarter in CapEx. When can that be – get to free cash flow neutral/positive? What do you need to do? Are still investing in CapEx in a way that can fall off in 2020 or something along those lines? Put 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're 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 to generate free cash flow.

Okay. Thanks very much.

Your next question comes from Tommy Moll of Stephens. Tommy, your line is open.

Good morning. Thanks for taking my questions.

Good morning.

Good morning.

So it's understandable that your visibility on leading-edge dayrates for super-specs is limited, just given that 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 and that'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 2016 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 it was relatively disciplined. You saw a relative discipline as we came out of that downturn in 2017 and 2018. And you saw pricing getting 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, the utilization is in the mid-90 percentile. There's no reason for there to be 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 smaller upgrades. Are those for rigs you anticipate putting the 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 were applied 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, higher towards double shoulder connection drill pipe. It could be an addition of [Indiscernible] 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.

Okay. Thanks. That's all for me.

Your next question comes from Jeffrey Campbell of Tuohy Brothers. Jeffrey, your line is now open.

Good morning.

Good morning.

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 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 up-take. In terms of the software application, the enhanced auto driller, 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 makes sense and where we can reach an agreement with the customer.

Okay, great. That's -- I appreciate that. And my other question was you mentioned the growing DUC inventory, possible up side to completions in the second half of 2019. I was wondering is that a view that's already embedded in the current spreads that are working or could that upside put out old crew spec for?

So, it could be recurrent 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, we had an acceleration in the DUC count towards the end of 2018 that at some point in 2019, we'll work through.

Okay, great. Thank you. Appreciate it.

And your next question comes from Ken Sill of SunTrust. Ken, your line is open.

Yes, thanks. I guess -- more of a philosophical question. You guys look at the foreign capital in the drilling business which has 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 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 spent in pressure pumping, because of all things you just described.

Okay. Well, 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 had 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 others?

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 on Oklahoma and the SCOOP STACK, the Anadarko basin, which were 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 up there that are playing things close to their best right now.

I'm probably not the best person to speak to what's happening up there other than in 2017 there was a lot of discussion about the SCOOP and STACK and how the economics would be similar to what we have in the Permian and 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. And we've seen a slowdown now in drilling activity in the MidCon and now we have a subsequent slowdown in services activity in the MidCon as well. So that -- from our view, it just hasn't materialized as some of the discussions lead to from 2017.

Okay, great. Thank you.

Your next question comes from Blake Gendron of Wolfe Research. Blake, your line is open.

Thanks for taking my question. Just one quick one for me. Even in the slight -- oil environment spending, it would seem that the Permian will drive the majority of 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 the not all super-spec rigs are created equal or is a pretty high substitute ability between super-specs and perhaps your two rigs? And then I guess, how does the software directional drilling upsell play into the competitive leverage in the Permian specifically? Thanks.

By nature of the definition of the super-spec rig where you're talking about our rig low capacity of 750,000 pounds plus, horsepower rating of 1,500 horsepower or greater while consistent high-pressure circulating systems, it makes that class of rigs relatively similar. But it all gets down to execution. So the hardware could we similar, but you're going to see differences in execution. We think that we’re 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 mechanically the rigs looks similar on paper, there is differentiation and execution in the processes that we run. And we think there's further differentiation by enhancing that offering with software capabilities that takes discrete processes on rigs and start to automate those processes.

Okay. Thanks. I’ll turn it back.

Your next question comes from Colin Davies of Bernstein Research. Colin, your line is open.

Thank you. Good morning. I’ve 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 -- increase level of discipline et cetera, but the obvious implication is that there is an impact on market share. Could you perhaps comment on that any extent to which you 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 you prepared to have customer relationships perhaps harmed by that transition in market share?

So one other thing that I'll point out and this is a history of the company, we're very margin focus company and there's really no point in chasing market share especially in the pressure pumping side of the business with a 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 will rebound. We try to stay focused on providing the best earnings results from that business. And reducing the number of spreads is strategy 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 again we understand there's also a large number of competitors out there and we're looking forward to seeing some of my competitors move in the same direction.

Yes. I mean and I guess the flip side of this 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 this particular part of the industry, it seems the customers had a pretty good, they’ve been able to push on price pretty aggressively. With invested 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 ramp that up yet benefit from that pricing competitiveness today. We'll just have to see how that works out to the rest of 2019.

That’s very helpful. Thank you.

I will just add one thing. There's a different companies out there some of which are in effect the uniform private equity backed entities that have not gone to 30-year-kind-of history that 30-plus year history that Patterson-UTI has in this industry. So we sort of play the longing. Some of these folks in effect 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.

Thank you. That makes a lot of sense. Thank you, I’ll turn it back.

And our final question comes from John Watson of Simmons. John, your line is open.

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

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 somethings we can do in 2019 to reduce fluid-end spend per hour of operating time as we work our way through 2019 as well.

Okay. Thanks guys. Appreciate it.

Thanks.

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

Just would like to thank everyone for participating in our Patterson-UTI conference call for -- the 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.