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Patterson-Uti Energy Inc  (NASDAQ:PTEN)
Q3 2018 Earnings Conference Call
Oct. 25, 2018, 10:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good morning, my name is Emily, and I will be your conference operator today. At this time, I would like to welcome everyone to the Patterson-UTI Energy Incorporated Third Quarter 2018 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer. (Operator instruction) Thank you.

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

Mike Drickamer -- Vice President-Investor Relations

Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's call to discuss the results of the three and nine months ended September 30, 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 the Securities Exchange Act of 1934.

These forward-looking statements are subject to risks and uncertainties as disclosed in the company's Annual Report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the company's actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statement.

The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com and in the company's press release issued prior to this conference call.

And now it's my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Mark Steven Siegel -- Chairman of the Board

Thanks, Mike. Good morning, and welcome to Patterson-UTI's conference call for third quarter of 2018. We are pleased that you are able to join us today. This morning, I will turn the call over to Andrew Smith, who will review the financial results for the quarter ended September 30. 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, and good morning. As set forth in our earnings press release issued this morning for the third quarter, we reported a net loss of $75 million or $0.34 per share on revenues of $867 million. Included in our net loss of $65.9 million of non-cash pre-tax impairment charges. Excluding these charges, our net loss for the third quarter would have been $21.1 million or $0.10 per share. These impairment charges include $48.4 million related to the retirement of 42 legacy non-APEX drilling rigs and related equipment, and $17.4 million for pressure pumping equipment.

As customer preference across the industry continues to shift to super-spec drilling rigs. These 42 rigs have limited and diminishing commercial opportunity. In pressure pumping the impairment was primarily related to obsolete sand handling equipment that has been replaced with more efficient solutions. Consolidated adjusted EBITDA for the third quarter was $202 million. During the quarter, we repurchased an additional 2.9 million shares of our common stock at the total price of $50 million. This brings our total repurchases for the year to up to $100 million or 5.5 million shares or 2.5% of the company's outstanding shares at the beginning of 2018.

In addition to the buybacks, we paid our regular quarterly dividend of $0.4 per share, which resulted in an additional $8.7 million return shareholders during the quarter. We will continue to evaluate buybacks given our expected level of free cash flow and competing capital needs. At September 30, 2018, we had approximately $200 million remaining under our share repurchase authorization.

During the quarter, we continued our practice of prudent use of financial leverage and ended the quarter with net debt to capital of 19.5%. Projected capital expenditures for 2018 remained unchanged at approximately $675 million. However, as we discussed last quarter, we've redirected some of our planned capital spending from pressure pumping to drilling reflecting the near-term opportunity set for both businesses. For the fourth quarter, depreciation expense is expected to be approximately $212 million, SG&A is expected to be $34 million, and our effective tax rate is expected to be approximately 17%.

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

William Andrew Hendricks -- President, Chief Executive Officer

Thanks, Andy. In contract drilling, our rig count during the third quarter averaged 178 rigs compared to 176 in the second quarter. The two rig's sequential increase was less than we expected as opportunities to increase our Canadian rig count did not materialize. Our US rig count during the third quarter matched our expectations, and the US market for super-spec rigs remained strong. The strong demand for super-spec rigs, average rig revenue per day for the third quarter was higher than we expected, with the $410 sequentially increased to $22,280. Average rig operating cost per day was in line with our expectation at $13,810.

Accordingly, average rig margin per day increased during the third quarter by $200 to $8,470. At September 30th, we had term contracts for drilling rigs providing for approximately $825 million of future day-rate drilling revenue. This was a sequential increase of more than 20% in one quarter, compared to our backlog at June 30th of approximately $680 million. Based on contracts currently in place, we expect an average of 127 rigs operating under term contracts during the fourth quarter at an average of 81 rigs operating under term contracts during the 12 months in the September 30, 2019.

Since the beginning of this year, we have completed 12 major rig upgrades, including one thus far in the fourth quarter. We have customer contracts to deliver two additional rigs with major upgrades later in the fourth quarter and two in early 2019. I'd like to note that while we use the term major upgrade, these rigs are essentially being built to like new condition. The rigs receiving the major upgrades are primarily lower capacity rigs that were built for drilling shallow wells, such as in the Barnett Shale. These rigs are undersized in the current market given the movement in the industry toward drilling deeper wells with longer laterals.

By replacing the original mast and substructure which collectively or commonly referred to at the center section of the rig, when the new center section for 750,000 pound hookload. We can upgrade these rigs to the specification of the super-spec rig and provide our customers with the drill pipe setback capacity they require. Additionally, for our major upgrades, we either refurbish or replace every major drilling system on the rig, resulting in an upgraded rig with similar component specifications and an expected useful life as a new build rig, but at a substantially lower capital investment.

Turning now to our contract drilling outlook, we estimate the current available supply of super-spec rigs in the US is approximately 625 rigs. Patterson-UTI is one of the market leaders with 145 super-spec rigs in our fleet as well as 53 APEX rigs that can still be upgraded to super-spec capabilities. However, these upgrades would be reliant upon customer contracts at compelling economics. We believe super-spec rigs across the industry are largely sold out and operators realize, they need to plan further ahead and consider higher price, longer term contracts in order to get in the queue for an incremental upgrade.

We are already having customer conversations about incremental super-spec rigs in 2019. This visibility gives us confidence the super-spec drilling activity will continue to grow. Rates will continue to rise and average contract durations will link that. For the fourth quarter, we expect our rig count will average 182 rigs, based primarily on increasing day rates, we expect our average rig margin per day to increase by approximately $500 million during the fourth quarter. We remain very pleased with our drilling business and are optimistic about its continuing prospects.

Turning now to pressure pumping, during the third quarter, we responded to the oversupply in the market by reducing the number of marketed spreads, and consolidating the work among the remaining spreads to reduce the white space in the calendar. We ended the third quarter with 21 marketed spread. Despite deteriorating market conditions during the third quarter revenues and gross profit were both better than we expected, as we build some of the white space expected during the quarter. Pressure pumping revenues for the third quarter were $422 million compared to $425 million in the second quarter, and pressure pumping gross profit was $79.1 million compared to $82.4 million in the second quarter.

For the fourth quarter, customers have been changing their plans on a regular basis, making it difficult to assess activity levels in white space on the calendar for the fourth quarter. With this uncertainty, we plan to manage our headcount for fourth quarter to maintain an adequate level of experienced personnel. Additionally, we will use this temporary slowdown in activity to perform maintenance on our equipment, to be well positioned to respond to incremental pressure pumping demand in 2019.

For the fourth quarter, we currently expect pressure pumping revenues of approximately $330 million to $340 million with a gross profit of approximately $55 million to $60 million. The year end slowdown in pressure pumping is expected to be temporary with activity increasing in 2019 as operators refresh their budgets. We are positive on the outlook for 2019, as increase in super-spec drilling rig activity continues to drive the drilled, but uncompleted well count, with the DUC counts higher.

The increase in the DUC count should accelerate over the coming months given the year end slowdown and completion activity as operator slow their work to remain within budget. A drawdown in the DUC count in 2019, as operators complete wells to fill incremental pipeline capacity, will have a significant positive impact on pressure pumping demand. We stand ready to quickly reactivate spreads, but have no intention of doing so until we see market conditions improve. While the activity slowdown of pressure pumping is creating a challenging market, in the short term, we believe that we are well positioned for an uptick in demand, which we foresee in 2019.

Turning now to directional drilling, revenues were $51.6 million for the fourth quarter compared to $52.7 million for the second quarter. Directional drilling gross margin is a percentage of revenues was 13.2% for the third quarter compared to 17.1% for the second quarter. During the third quarter, we reclassified certain items from SG&A to direct operating costs, which negatively impacted gross margin, but do not have an impact on the segment bottom line. Additionally, operating expenses in the third quarter were impacted by increases in expenses for both personnel and repairs and maintenance.

We believe the increasing repairs and maintenance expense is a prevalent challenges across the directional drilling industry today. The increasing wear and tier from higher drilling intensity, including high-pressure systems of modern super-spec drilling rigs is harder on down-hole directional drilling equipment leaving to more frequent repairs. We believe over the long-term directional drilling pricing needs to increase in order to offset these higher expenses. For the fourth quarter, we expect directional drilling results to be similar to the third quarter.

Turning now to other operations which include Great Plains Oilfield Rental, Warrior Rig Technologies in our E&P business. Revenues during the third quarter increased sequentially to $29 million and the gross margin as a percentage of revenues was 29.6%. For the fourth quarter, we expect similar results to the third quarter.

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

Mark Steven Siegel -- Chairman of the Board

Thanks, Andy. Fundamentals remained strong for US onshore drilling and completion activity. Continued growth in super-spec drilling activity has been driving growth in the number of DUCs. The expected fourth quarter slowdown in completion activity combined with increasing drilling activity should cross the growth rate in the DUC count to accelerate. This increase in the DUC count bodes well for an increase in future pressure pumping demand. We expect this demand will begin to materialize early in 2019, as E&P capital budgets reset based on higher current commodity prices than in the prior year.

This expected increase in pressure pumping demand in 2019 is also supported by favorable macro backdrop for the energy sector. Global economic growth continues to drive increasing demand for oil, while supply growth is being negatively impacted by geopolitical issues and several years of under-investment in new large-scale, oil and gas projects. Additionally, the amount of spare oil production capacity available to offset supply disruptions is both dwindling and unproven.

The favorable macro environment is already apparent in contract drilling, which accounted for approximately two-thirds of our EBITDA. We see great value in our position as a leading provider of super-spec rigs. Let me reiterate Andy's comments that super-spec rigs are largely sold out, requiring operators to get in the queue and wait for an upgrade, if they would like to add an incremental super-spec rig. This queue, and the resulting conversations about longer-term drilling plans is allowing us strong visibility into future super-spec rig demand.

Additionally customer appetite, for term contracts in a rising day rate environment confirms the super-spec drilling activity should remain strong. 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 December 20, 2018 to holders of record as of December 6, 2018.

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

Operator, Emily, we would now like to open the call to questions.

Questions and Answers:

Operator

(Operator Instructions) And your first question comes from the line of Marshall Adkins with Raymond James. Your line is open. Please go ahead.

Marshall Adkins -- Raymond James & Associates, Inc. -- Analyst

Good morning, guys. Your frac business of this quarter is meaningfully outperforming most all the peers that have reported. Two questions I have on that. Number one, could you give us more color on how you were able to achieve that? And know you brought the count down a little bit, would probably help margins, but just give us a broader picture of how you've remained more competitive than average, number one. And then number two, you gave us great guidance on Q4, thank you for that. I'm also curious as to some speculation on how you see the market unfolding next year. Is it a second half of the '19 recovery for pressure pumping? Or do you think it happens sooner? So, those are my two questions.

William Andrew Hendricks -- President, Chief Executive Officer

Good Morning, Marshall. So, thanks for the question. In terms of pressure pumping and what we're seeing in the market, if you go back to our second quarter earnings call, we were saying that we are already seeing that the market was oversupplied, the third quarter had uncertainty with a fair amount of white space in the calendar, it was kind of a challenge to really understand how much white space we're going to see and as we work through the quarter, our teams did a great job trying to respond to what was happening in the third quarter and make sure that we were right size, as things materialize.

Our teams also did a great job filling some of that white space in the calendar, in the third quarter as well, which allowed us to do little more revenue than we thought we were going to do the projections that we gave you on that July call and -- for the second quarter. So, that's really what it was, there was a lot of basic blocking and tackling in the pressure pumping business just to try to make sure that we are right-sized as we work through that quarter and so we brought the number of spreads down from 25 at the beginning of the quarter, down to 21 spreads at the end of the third quarter.

Marshall Adkins -- Raymond James & Associates, Inc. -- Analyst

(inaudible) with those. Just a quick follow-up there. Were those spot or dedicated fleets you were actually able to fill the white space? I assume its spot market, but just out of curiosity.

William Andrew Hendricks -- President, Chief Executive Officer

Yeah, filling white space right now is basically just picking up spot work in inserting it where you may have delays or breaks in your current schedule. And those delays of rates could be on spot or on dedicated agreements. The majority of our spreads do work on dedicated agreements, but we do see customers slowing down and pulling back on spending right now, especially in the fourth quarter.

Marshall Adkins -- Raymond James & Associates, Inc. -- Analyst

Okay. Sorry, go ahead, Mark --

Mark Steven Siegel -- Chairman of the Board

Yeah, no problem. I just thought I would jump in a little bit. We've seen as you well know, an increase in the DUC count of approximately 25% from January through the end of the third quarter and DUC count -- is probably going to increase during the fourth quarter as E&P delay completions for various reasons. We feel that they're going to want to complete those wells early in 2019 and so exactly timing the particular day, month, year they do that is hard, but we think it's definitely a first half 2019 kind of prospect.

Marshall Adkins -- Raymond James & Associates, Inc. -- Analyst

Perfect. That's helpful guys. And I'll turn it back over. Thank you all.

William Andrew Hendricks -- President, Chief Executive Officer

Thanks.

Operator

Your next question comes from the line of Sean Meakim with JPMorgan. Your line is open. Please go ahead.

William Andrew Hendricks -- President, Chief Executive Officer

Thank you. Hi, good morning.

Sean Meakim -- JPMorgan Securities LLC -- Analyst

I think investors are going to applaud that decision to stack equipment rather than fight for work in the year-end. But certainly as you look forward to 2019, what would be your best guess -- maybe a similar question but asked in a different way. How long you think it takes for activity, for pumping activity to get back to 2Q, 3Q type of levels? And when it does, is it fair to say that given some the operational challenges you all had earlier in the year, that you expect to be able to get your profitability higher or in natural environment compared to what you delivered say in 2Q, '18 ?

William Andrew Hendricks -- President, Chief Executive Officer

So the timing of some of how this is going to materialize is still yet to unfold in 2019, but we're very upbeat on 2019 in terms of completion activity just based on what we're seeing in drilling activity. Our drilling business gives us a lot of foresight and marketing knowledge on what's happening in the industry. So, we really feel like there's going to be an acceleration in the inventory of the drilled, but uncompleted wells in the fourth quarter and going into the start of 2019. We do have some customers that say they're going to be starting in early 2019 on the completion side right after the year starts and the budgets reset.

So, we're already getting some of that discussion with some of the customers now, how much and how fast, I think it's difficult to predict. There's several things happening in 2019, you have the budgets resetting at higher commodity prices we discussed, you also have some of the takeaway capacity in the Permian continuing to improve and in the budget issues aren't limited to the Permian, that's across the US onshore. But of course, the takeaway capacity improves as well, you're going to give enough to lift completion as operators prepare for that increased takeaway in advance.

Sean Meakim -- JPMorgan Securities LLC -- Analyst

And then any other comments on how you expect your profitability to shape up in that type of environment, whenever that does materialize relative to you did this year?

William Andrew Hendricks -- President, Chief Executive Officer

Yeah, as I said, we've been very focused, all through 2018 on trying to improve our profitability in pressure pumping, and we're going to remain focused on that. We don't think it's about market share and we do think it's about trying to maintain the profitability per spread and pressure pumping.

Sean Meakim -- JPMorgan Securities LLC -- Analyst

Thank you for that. And then just thinking about capital allocation for next year. Can you maybe just walk us through how do you think about prioritization of cash uses, directionally, do you think CapEx will be higher or lower? You got of course upgrade potential you see continuing to unfold, but then perhaps reactivation is something that CapEx on the pumping, you end up being less than what you experienced in '18. Just maybe kind of where you see things based on what you know today?

William Andrew Hendricks -- President, Chief Executive Officer

I guess the -- response that I'd like to give you is that we said our capital budgets in Late December, sort of operating and capital budgets in late December, and we feel that by doing so at that time we have some maximum visibility into #### that company could have. We typically have followed the rule of announcing our plans for capital expenditures in our call in February, as we've announced fourth quarter results.

So, I expect that we're going to continue to follow that same approach this year, with that said, I think that we're very focused on returns and that return focus is really causing us to think seriously about every dollar we spend, as we always have. I'd also point out, the fact that we have returned substantial amounts of capital to the investors already two, three quarters of this year in the forms of a substantial amount of buyback as well as dividends. And quite frankly, that buybacks and dividends and that return of capital seems to have gone relatively unnoticed by our shareholders and the -- analysts community and I just want to call that out as being a very important part of the story, I think for this year.

Sean Meakim -- JPMorgan Securities LLC -- Analyst

Fair enough. Thank you, guys.

Operator

Your next question comes from the line of James Wicklund with Credit Suisse. Your line is open. Please go ahead.

James Wicklund -- Credit Suisse Securities -- Analyst

Good morning guys. Mark on the statement, on the comment of returning cash to shareholders. You guys obviously aren't in a better time in the market then we are. So I sure can't criticize. But if you look at where you bought stock this year, it was higher. Have you guys considered just having a constant buyback instead of an episodic buyback? Or do you just buy it back when it's cheap and you keep buying back as it gets cheap? What's the methodology that you guys have for deciding to buy stock, buy stock.

William Andrew Hendricks -- President, Chief Executive Officer

Well I guess, I would quarrel, Jim, with your concept that we are doing it episodically and that we're doing it at the top, what we've done historically is buy stock during each of the three quarters so far during this year. And we've done so kind of in a regular program that has been very even across the days, months or period of time where the market is open for the company. So, quite honestly, I think it's been pretty strategic in a market such as the one we are facing in which the stock price has trended lower the whole year it figures that the stock you bought in the early part of the year is more expensive than the stock you bought in the later half of the year. The reverse would have been true, if we were in an uptick, a rising market. And so it's one of those things where I don't see that anybody who's involved in a buyback program can always time the market.

James Wicklund -- Credit Suisse Securities -- Analyst

No, no. I'm not arguing. Like I say companies don't do it any better than us. And it's not that it's been episodic. I'm just saying that there is several different options, one is regular a stated one is episodic and one is just you decide to buy it back and it seems to be the latter, you bought back stock three quarters in a row. I'm just wondering what methodology you guys use then to decide this quarter, the stock price is x, and our bell ring is on Y. What's Y? What do you look at to decide whether to buy the stock tomorrow.

William Andrew Hendricks -- President, Chief Executive Officer

Jim, I guess I wish it was just a two factor decision, but it's a multiple factor decisions we are thinking about what is our free cash generation. We're thinking about what is our expected capital expenditures, we're thinking about possible M&A opportunities, we're thinking about all kinds of other variables not a cash available to us, lines of credit, situations of that sort, all kinds of variables, as well as stock price. And so at each given point our Board and management conclude what they think, or what we collectively think is the right approach for the next quarter and then execute it.

Mark Steven Siegel -- Chairman of the Board

Jim, I will add, you know when it comes to running the business, we're really focused on trying to maintain capital discipline especially around capital expenditures whether its maintenance in trying to be smart about how we spend on maintenance or on the growth side where we're trying to derisk the dollars that we're investing in the growth CapEx and minimizing that in the history of the company has returned cash to shareholders as you well know and so it's part of my job to make sure that we minimize any capital expenditures and help generate free cash flow and so we can return cash to shareholders and then we have to find the best mechanism to do that after that.

James Wicklund -- Credit Suisse Securities -- Analyst

And you've done a great job of allocating capital to your different parts of the business and focusing on returns. It just sounded more like it was availability of capital and where the stock price was as opposed to some metric of return based on the stock price. That was really my only point. My follow-up, if I could -- I'm sorry go ahead.

William Andrew Hendricks -- President, Chief Executive Officer

It's certainly a function of what we believe our free cash flow is after CapEx during a given quarter as well.

James Wicklund -- Credit Suisse Securities -- Analyst

Okay. My followup if I could, is really on Directional Drilling. When you guys first bought this, the guidance was we can get this thing to 30% margins. And I know that you reallocated some cost this quarter and that puts it 13, but it just back of the envelope it was adjusted if you wouldn't have done that, I guess it was closer to 16. It kind of isn't living up to your expectations you note that you need pricing. Has that been -- are you behind plan and where you expected to be in your Directional Drilling business right now?

William Andrew Hendricks -- President, Chief Executive Officer

I think it's safe to say that yes, we are behind plan and hasn't been generating the margins that we've been aiming for in 2018. We are still working with the management teams to make every effort to improve that there's efforts under way to improve the operating cost to run some of this equipment in the harsh environment that we're doing with the super-spec rigs. We're also going to make every effort to push pricing is the recap continues to improve as well.

James Wicklund -- Credit Suisse Securities -- Analyst

Can you get to 20% margins without price?

William Andrew Hendricks -- President, Chief Executive Officer

I think, we're certainly focused on improving the margins where that goes from here based on the challenges in '18, it's a little bit more difficult to call out today, but --

James Wicklund -- Credit Suisse Securities -- Analyst

Understand. Okay. Thanks guys. Appreciate it.

Operator

Your next question comes from the line of James West with Evercore ISI. Your line is open.

James West -- Evercore Group -- Analyst

Hi, good morning guys.

William Andrew Hendricks -- President, Chief Executive Officer

Good morning.

James West -- Evercore Group -- Analyst

I wanted to focus on the main driver here of earnings, particularly over the next couple of quarters, the rig business. So, you've got, I think Andy you said 53 now APEX rigs that can be upgraded to super-spec down from I think 56 or so recently. As you, I know you guys are going to be very careful on capital and what you put into the market and so you're going to want to have contracts, but as you have these discussions with customers, are you starting to order long lead-time items developing an inventory, so that when they do hit go on contracts, you can get out there quickly.

William Andrew Hendricks -- President, Chief Executive Officer

Yeah, James. Thanks and as you know, as we look at these major upgrades and with the investment to take to do this, we want to derisk the dollars with the long-term contracts to be able to do this at good day, rates it gives you the economics, but of course, we have to keep some long lead items in the order process and that's within the current CapEx budget that we gave you. So, we are ordering some of the longer lead items for delivery into 2019, if we don't end of using those to upgrade rigs will hold in the spares. These are not large dollars compared to the overall budget. But we do want to say, slightly ahead on long lead items, but we wouldn't build a rig on spec or upgrade a rig on spec.

James West -- Evercore Group -- Analyst

Okay. And then should we expect based on the conversations and you're having plus the outlook for the industry overall. Should we expect the same type of cadence of upgrading rigs as we've seen in the last year or two? I mean just like a 10, 15 per year or so.

William Andrew Hendricks -- President, Chief Executive Officer

Well, we mentioned that we have two to deliver early in 2019 and as we discussed, we're getting some long lead items already on order. But I think it's too early to tell exactly what the cadence is going to look like in 2019. I think the good news is that we're in discussions with customers for 2019 beyond the two major upgrades and we plan to deliver early in the year. But as to what that Cadence is going to look like, I think it's still a bit early.

James West -- Evercore Group -- Analyst

Okay. Got it. All right. Thanks, Andy.

Operator

Your next question comes from the line of Marc Bianchi with Cowen. Your line is open. Please go ahead.

Marc Bianchi -- Cowen & Co. -- Analyst

Thank you. Following on the upgrade conversation you've got these four more rigs that are going into the market here in fourth and first. What kind of contract term do these rigs have and what are the payback periods look like for the upgrade that you've -- upgrade investment you've done.

William Andrew Hendricks -- President, Chief Executive Officer

Yeah, so for the four major upgrades that we announced on the Q2 earnings call, we said that we signed contracts for four years for each of those rigs and that the payback period based on those day rates and margins is within that four year period of those contracts.

Marc Bianchi -- Cowen & Co. -- Analyst

Andy, when you --

William Andrew Hendricks -- President, Chief Executive Officer

Two rigs -- two rigs that are being delivered at the end of this year and two rigs delivered in early 2019.

Marc Bianchi -- Cowen & Co. -- Analyst

Okay. And when you calculate that payback that's on the -- is that on the total margin or is that on the addition margin that you're getting because of the upgrade investments you're making?

William Andrew Hendricks -- President, Chief Executive Officer

I guess we don't separate the two. We look at it in terms of the day rate that we're getting on the rig for that upgrade and what that payback is based on the cash spent.

Marc Bianchi -- Cowen & Co. -- Analyst

Okay. And then as you look at opportunities beyond these four, would you say that they would be similar with that four year term and pay back or are you seeing things evolve differently?

William Andrew Hendricks -- President, Chief Executive Officer

I think it's too early to say how things are going to evolve past those contracts. But I think suffice it to say that we do need long-term contracts. You know good day rates in order to do more of these upgrades and finish some more of these rigs.

Marc Bianchi -- Cowen & Co. -- Analyst

Got it. Okay. Maybe if I could just one more on the pumping side. The fleets now you've got 21 in the field and four that you've put on the sidelines. Given what you see here over the next quarter or two. Would you say is it fair to say that, unlikely you would be stacking additional fleets and kind of curious what the utilization opportunity is on the 21 that you've in the field right now, maybe how much white space there is to be absorbed as activity comes back up?

William Andrew Hendricks -- President, Chief Executive Officer

So, we plan to operate 21 spreads during the fourth quarter based on projections that we have. There is some white space in that calendar just because of seasonality that's built into some of that workload. And that's not likely to change in the fourth quarter, but it could have some variability, so it is a bit challenging to protect. That continues on likely into the first quarter, but at the same time, you get some budget reset from the customers. And we already in discussions with some customers who want to restart early in the fourth quarter. So, we certainly intend to hold onto experienced personnel and we're going to make every effort to be ready to respond. Again, our focus is going to be on margin per spread and so we want make sure that we're maximizing that as we activate in an upturn in 2019.

Marc Bianchi -- Cowen & Co. -- Analyst

Okay. Well, thanks for that. I'll turn it back.

Operator

Your next question comes from the line of Jud Bailey with Wells Fargo. Your line is now open. Please go ahead.

Judson Bailey -- Wells Fargo Securities -- Analyst

Thanks, good morning. Follow up there, on pressure pumping, if I could, if I look at the revenue guidance, and the gross profit guidance kind of back into a decrement, that's probably the mid 20's. I think, I'm doing the math right and if I am correct, what are the drivers to keep decrements at a such a reasonable level given the magnitude of the revenue drop. Is it, visibility on pricing or something you're doing on the cost side? I know you said you rationalizing costs as best you can. But I would assume you're trying to keep staffed up, like you said as well to be ready when things recover. So, could you help us kind of think through the, kind of what you're suggesting from decremental margin standpoint for the fourth quarter?

William Andrew Hendricks -- President, Chief Executive Officer

You know, as we worked our way down in the third quarter from 25 to 21. We are trying to ensure that we're keeping the costs in line when we do that, so going into the fourth quarter, again, we have a lot of emphasis on costs and spending and keeping that tight in the fourth quarter. We've got some white space in the fourth quarter as well and there's going to be a shift in the mix of the customers with the shrinking from 25 to 21. So, there is various moving parts that are in there.

Judson Bailey -- Wells Fargo Securities -- Analyst

Okay. And is there in that guidance is our contemplated any weakness and our roll over into lower pricing or are you pretty much set from a pricing standpoint, this quarter from what you can tell today?

William Andrew Hendricks -- President, Chief Executive Officer

For the most part, our spreads are working at dedicated crews of under dedicated agreements. And on those dedicated agreements, we're not currently seeing a lot of pressure in terms of renegotiating the pricing, it's only when we try to fill white space in the calendar and we want to grab some spot work for short-term interval that we see a differential on the pricing. But for most of our crews and we're not seeing that pressure right now.

Judson Bailey -- Wells Fargo Securities -- Analyst

Okay. Great. And if I could squeeze one more in, just thinking one more question on CapEx. Am I fair to think that this level of activity as you kind of exit the year that your maintenance CapEx is probably around 350 as a baseline as we had in the '19 and then on top of that will be any growth. I just want to make sure I'm kind of thinking about that number correctly?

William Andrew Hendricks -- President, Chief Executive Officer

I think it's really too early for us to comment on exactly what that's going to look like or call out a number right now, because of the changes in activity and some of the things that we're doing to try to tighten that maintenance CapEx spendings. We will just have to get back to you later on that.

Judson Bailey -- Wells Fargo Securities -- Analyst

Okay. Thanks. I'll turn it back.

Operator

Your next question comes from the line of Tommy Moll with Stephens. Your line is open. Please go ahead.

Tommy Moll -- Stephens, Inc. -- Analyst

Good morning. Thanks for taking my questions.

William Andrew Hendricks -- President, Chief Executive Officer

Good morning.

Tommy Moll -- Stephens, Inc. -- Analyst

So, on the 53 upgrade opportunities that you've got left. How many of those rigs are currently idle versus active? And then for those that are idle, are we looking at the roughly 15 million a piece CapEx to perform the upgrade and then for those that are active. Is it a similar level of CapEx or a lower level?

William Andrew Hendricks -- President, Chief Executive Officer

So Mike pulling up on the numbers on which of the 53 are active right now. Yes, some of those 53 APEX rigs are currently working and then some are idle. If those rigs are currently working, there's -- they are relative fit for the market with some of those that are currently working. Mike just gave you the numbers. So, we have 32 of the 53 that are idle. But the ones that are currently working may only need to add locking system. They may only need to add high pressure circulating systems. So, you're talking about $1 million to $5 million investment there depending on the rig. The ones that are idle may needed a much larger upgrade in the range of that $15 million. And so again for us to do that, we would want some kind of long-term contract that economically makes sense to do that. The good news is, that we are in discussions with customers in 2019, the super-spec rig market is tight. We see demand for super-spec rigs and we see that continuing into 2019 and we're very upbeat about the drilling business.

Tommy Moll -- Stephens, Inc. -- Analyst

Is it fair to assume that the next batch of upgrades are most likely to come from the Idle stack and then once that is depleted there'd be a meaningful leg up in terms of pricing power because it's -- when you get into upgrading and active rig your payback calculation would look different. I would suppose because it's not a function of zero gross margin today versus something under a contract, but you already generating a pretty good margin and therefore might need more incentive on the pricing side to perform the upgrade. Is that fair?

William Andrew Hendricks -- President, Chief Executive Officer

So, without having individual rigs schedules in front of me and just making some assumptions there. If an APEX rig is working today is likely to keep working. So, for those rigs that are working, we are not likely to bring them in, and do any upgrades or likely to stay working in the condition that they're in and we probably be talking about the idle APEX rig and some major upgrades that becomes incremental to the rig count if we do that. So, you'd have existing APEX is we continue working and then as the market conditions continue to improve, but we were able to sign those long-term contracts for rigs in 2019, then those will be incremental to the rig count.

Tommy Moll -- Stephens, Inc. -- Analyst

Okay. Thank you. That's all for me.

Operator

Your next question comes from the line of Chase Mulvehill with Bank of America Merrill Lynch. Your line is open. Please go ahead.

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

Hey, good morning. I guess the first question, just kind of keeping on the land rig theme, I was surprised to not to see new upgrad announced during the quarter. So, could you maybe just talk about to the number of bids outstanding for major upgrades. How has that trended recently, has that started to trend down and if so, what do you think is driving the less number of bids a lower number of bids out there today.

William Andrew Hendricks -- President, Chief Executive Officer

Yes, first off, I wouldn't necessarily characterize them as bids. These are really discussions and negotiations between us and the customers it's not necessarily that our customer goes out to bid, and get pricing it's more of a discussion, which is positive because we are talking about operators entering into long-term contracts. What we consider a higher day rates and so that's more than just a bid type situation. But I think the reason that we don't have more contracts to announce right now is really a function of the timing and where we are with operators budget cycle.

The operators are working on their budgets right now and so when you get to the drilling department level as an operator -- organization, they likely don't have internal improve yet to discuss the further the rig adds although we're in discussion of what their potential plans are for next year. It's -- they've got into their budget cycle before the drilling departments have that level of approval. And so I don't think we're going to hear more -- we're not going to hear more definitive information from the operators until later in this year early next year, but again this market is tight. Operators are in discussions with us now because they understand there's a queue out there and they understand, if they want a rig, they've got to get in the line.

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

Okay. And if somebody would have come to you today and want you to upgrade a major upgrade with one of your rigs, when would you be able to deliver it?

William Andrew Hendricks -- President, Chief Executive Officer

That first one from a discussion today would be available late in the first quarter or early second quarter.

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

Okay. And then the gross margin per day was guided to be up 500,000 a day. How -- what's the OpEx component of that? Is OpEx kind of flat or is it going to be down?

William Andrew Hendricks -- President, Chief Executive Officer

In the drilling rig business, we expect OpEx in the fourth quarter to be roughly level from the third quarter.

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

Okay. If I could squeeze one more in. Can you just talk a little bit about leading edge super-spec dayrates. And then if that's actually starting to have an impact on kind of some of the lower spec rigs and bringing those dayrates up yet.

William Andrew Hendricks -- President, Chief Executive Officer

So, what we're seeing in terms of leading edge and we said this at the last quarter this leading edge was around the mid '20s on contracts that we were signing for delivery in early 2019, and I would say that leading edge is still that mid '20s and pushing up a little bit from there. So, I think we are seeing from that mid 20 level without pinning down to a number that we still see those pricing levels from discussions potentially moving up from that mid '20s level.

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

Okay. Just starting to have an impact of some of the high spec, lower spec rigs and pull those rates up as well.

William Andrew Hendricks -- President, Chief Executive Officer

Yeah. There's no question in the market is the pricing on the super-spec rigs moves up, it's listing the pricing on other rigs in the market and the tightness in the demand for the super-spec, as well as I think keeping other rigs active through the rest of the year and we'll probably generate some interest for instance, our non-APEX rigs in 2019.

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

If you squeeze at those two dayrates have the differential has it narrowed?

William Andrew Hendricks -- President, Chief Executive Officer

I would say it hasn't narrowed yet, but it's likely to move in that direction as we move into 2019.

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

Okay, awesome. I'll turn it back over. Thanks, Andy.

William Andrew Hendricks -- President, Chief Executive Officer

Thanks.

Operator

Your next question comes from the line of Taylor Zurcher with Tudor, Pickering, Holt. Your line is open. Please go ahead.

Taylor Zurcher -- Tudor, Pickering, Holt & Co. Securities, Inc. -- Analyst

Good morning. Thanks. Andy for the first spreads that you stack during Q3. Could you give us some color as to which basins in plays those spreads were previously working and then maybe more high level as we think about that the four primary geographic regions you operate in pressure pumping those being Eagle Ford Permian and Northeast and Mid-Continent. Are you seeing this similar softness across all four or is the softness more acute in one versus the other?

William Andrew Hendricks -- President, Chief Executive Officer

So, in terms of spreads that we're not marketing today, that softness is really around Texas and Oklahoma for the most part, but I think as we've discussed, we have the potential for recovery in 2019 because we're not seeing the drilling rig count slow down. On the contrary we are seeing the drilling rig count for ourselves move up in the fourth quarter and that's going to drive an acceleration in that DUC inventory and I'm sorry, what was the second part of your question?

Taylor Zurcher -- Tudor, Pickering, Holt & Co. Securities, Inc. -- Analyst

That answered it. I was just basically just curious today -- if one region was softer than the other, but that answered it. And maybe a follow-up, it sounds like at least on the dedicated side your pricing has stayed relatively consistent. I just wonder as you fill the white space in sort of the spot market what the delta is in pricing between spot market today versus some of your dedicated pricing today?

William Andrew Hendricks -- President, Chief Executive Officer

In terms of a delta in the pricing between what we're getting on dedicated and what we fill gaps in the calendar on spot, I actually think it's kind of hard for me to call out. I think it can vary within a range and I don't think I can give you a good number right now. Definitely the spot price is lower. There is a lot of competition there. That's a bit more challenging, but very pleased to see that pricing is essentially holding up with the dedicated agreements that we have.

Taylor Zurcher -- Tudor, Pickering, Holt & Co. Securities, Inc. -- Analyst

Okay, appreciate it. I'll turn it back.

Operator

The next question comes from the line of Blake Gendron with Wolfe Research. Your line is open. Please go ahead.

Blake Gendron -- Wolfe Research -- Analyst

Hi, thanks, guys. Wondering if we can get some clarity on the efficiency trends that you're seeing both on the drilling side and the pressure pumping side, appreciating your DUC comments. The pushback that we've gotten from investors is that you're starting to see rig efficiencies kind of playing out here, I guess, offsetting that as maybe lateral lengths are starting to stagnant at the leading edge. You're hearing about pressure pumping spreads becoming more efficient and perhaps running into the rigs. So, what would you guys say just given you play on both markets, what you're saying at the field level on both sides and maybe how does that follow through to the DUC count moving forward.

William Andrew Hendricks -- President, Chief Executive Officer

You know I think we have seen efficiencies improve in 2018 and we look at efficiencies in terms of how many stages can a spread do within a given time period whether it's per month, per quarter, et cetera, and so how that's how we look at efficiencies and we have seen efficiencies improve. Some of that is driven by the move and the shift you're seeing primarily in West Texas to more zipper fracs. But when we do more zipper fracs we are also consuming more horsepower per spread so it takes more horsepower on location to make sure that everything has the proper uptime to be able to do that because zippers is more of a continuous pumping operation than a non-zipper operation.

Other basins have been doing zippers for a while especially the Northeast, a little bit in South Texas. So, you're seeing the shift in the Permian, but I'm not sure how much you'll continue to see the shift past 2019. So, we'll have to wait and see how much we get to consume there. But again we are seeing that and it's been driven by the shift to the zipper, so we'll have to wait and see some commentary on E&Ps and how that moves for the rest of the year.

Blake Gendron -- Wolfe Research -- Analyst

Okay. Great. And then can you just remind us what you guys have on the sidelines as far as horsepower goes? And then as we look into 2019 in that market improving, do you see the same number of nameplate active spreads going back to work or you're going to have add incremental horsepower to beef up those spreads or perhaps you are going to rationalize horsepower and consolidate to a fewer number of spreads.

William Andrew Hendricks -- President, Chief Executive Officer

So, I think the rationalization on our side occurred in the third quarter when we dropped from 25 to 1. But at the same time as we move into 2019, as we do reactivations, if those reactivations per spread, if it was not doing zippers before and it's going to start doing zippers as we mentioned, it's going to have to have a little bit more horsepower per spread to be able to do that. So, I think it's kind of hard to project exactly what that's going to look like in terms of where those spreads may land, which operators, which agreements they are going to go into. So, I think it's a little bit early to talk about. But again as I mentioned we don't anticipate working more than 21 spreads in the fourth quarter, but we are in some discussions for early 2019 about some reactivations to get started in the year.

Blake Gendron -- Wolfe Research -- Analyst

Awesome. That's helpful. Thanks, guys.

Operator

(Operator Instructions) And your next question comes from the line of Ken Sill with SunTrust Robinson Humphrey. Your line is open. Please go ahead.

Ken Sill -- SunTrust Robinson Humphrey, Inc. -- Analyst

Yes, thanks. I was wondering how I was going to get in here. So, just want to ask the question from the last time again, how much active horsepower do you have or what's the average horsepower per fleet now that you're down to 21 fleets?

William Andrew Hendricks -- President, Chief Executive Officer

Yes, we are not calling it out right now. I mean it's moving depending on where these spreads are working. Even the spreads -- even the 21 spreads that we are working in the fourth quarter, if we are doing we might be working on one type of pad where it's not a zipper. It might shift over to a different pad where it is a zipper and that could be in the same -- for the same customer within the same agreement and then that's going to move the amount of horsepower per spread. So, it's something that we see shifting right now even within dedicated agreements that we have.

Ken Sill -- SunTrust Robinson Humphrey, Inc. -- Analyst

I guess to the extent that you're moving to more zippers in the Permian, then we should just expect the average horsepower per fleet is going to go up a little bit from where it was on average for the first part of 2018?

William Andrew Hendricks -- President, Chief Executive Officer

I think when you look at it from an industry standpoint, as Permian increases the amount of zippers they are doing, it does require us as an industry to increase the amount of horsepower per spread.

Ken Sill -- SunTrust Robinson Humphrey, Inc. -- Analyst

Okay. And then just kind of parsing into the slowdown, you guys are looking at a 25% decline in revenue sequentially. How much of that is people actually saying they're slowing down because of capacity constraints or just we've exhausted budgets or it's just kind of it's been a long year we're going to take some time off for the holidays.

William Andrew Hendricks -- President, Chief Executive Officer

You know it's a mix of all the above right now, but we're certainly not going to say that the capacity constraints aren't part of it. We think they are part of it, but the majority of what we are seeing are E&Ps trying to stay within their budgets and their spending that they broadcast to the Street and trying to hold back and they are doing that through seasonality, through slowing down at holiday periods here as we get toward the end of the year, et cetera. But we recognize there's capacity constraints in the Permian but we're seeing pull back across the U.S. not just the Permian and a lot of that has to do with budget constraints.

Ken Sill -- SunTrust Robinson Humphrey, Inc. -- Analyst

Yes, -- that's the one that's been hard to figure out lot because a lot of people are saying they haven't seen much constraint yet but there is definitely a slowdown. Last question here is after you wrote off the 42 non-APEX rigs, how many non-APEX rigs do have left and how many of those are working versus idle?

William Andrew Hendricks -- President, Chief Executive Officer

So, in the fleet that would leave us with 252 rigs, that's 198 APEX and 54 non-APEX. In terms of the non-APEX that are working, we have 17 non-APEX rigs that are working today.

Ken Sill -- SunTrust Robinson Humphrey, Inc. -- Analyst

Okay. Great. That's all I needed. Thanks.

William Andrew Hendricks -- President, Chief Executive Officer

Thanks.

Operator

Your next question comes from the line of Colin Davies with Bernstein Research. Your line is open. Please go ahead.

Colin Davies -- Sanford C. Bernstein & Co. -- Analyst

Thank you. Just a question around what you have done around some of the variable cost for the laid-down or the idled frac fleets, obviously, if you're talking about reactivations in the first quarter or early in the year that may be a different strategy. Then, if it's more related to Texas and perhaps a Permian ramp in the second half of 2019. Can you just perhaps give a little color on perhaps the people side and the variable cost?

William Andrew Hendricks -- President, Chief Executive Officer

Yes. So, as we've reduced the amount of activity that we have in the third quarter from the 25 to the 21, we certainly want to try to keep our cost in line. We do have turnover in this industry, that is not something that's just Patterson-UTI specific, but the industry has head count turnover that's still relatively high, the job markets are tight across the U.S. So, we can allow the turnover to bring our compensation cost down, but at the same time we want to hang on to experienced personnel because we do believe that we have upside in 2019 and we believe it will be reactivating the spreads at some point in 2019. So, we are doing different things to manage that cost and the spending, but some of it is around head count.

Colin Davies -- Sanford C. Bernstein & Co. -- Analyst

Yes. And then I was just intrigued by your comments around Directional. Just wondering whether there's perhaps any thoughts around whether the more structural pricing problem? I mean obviously the massive increase in drilling efficiency over the last few years makes a challenge if you're being paid by the day rather than the foot. I mean is there more of a structural problem there in terms of the industry is mechanisms for pricing for directional services?

William Andrew Hendricks -- President, Chief Executive Officer

No, that's an interesting question and the directional industry has kind of moved back and forth between, do we charge by the foot? Do we charge by the day? And it's changed at different periods in time in the industry and really depends on how we have to be able to manage the risk in operations and what we have control over and what we don't have control over. So, I think we'll continue to look at that as an industry. I think that as I mentioned we think the pricing needs to come up in the directional drilling sector. With the super-spec rigs out there with the 7,500 psi circulating system, the flow rates are much higher.

So, the wear and tear on the downhole equipment in the directional drilling side is higher as a result of that and I don't think we'll be the only ones that will be pushing for higher price to cover those additional costs. I'm sure that others are seeing that materialize in their repair and maintenance cost this year as well with the increasing percentage of super-spec rigs across the industry.

Colin Davies -- Sanford C. Bernstein & Co. -- Analyst

That's really helpful. Thanks very much.

Operator

Your next question comes from the line of John Daniel with Simmons and Company. Your line is open. Please go ahead.

John Daniel -- Simmons & Company International -- Analyst

Guys, thanks for putting me in keeping the call going. Andy, as you begin your 2019 budget for the frac business, can you speak to the decision to either rebuild some of the existing equipment or perhaps buy new equipment to replace legacy? And specifically, do you see any new equipment designs or component part technology which would warrant sort of a more methodical and newbuild/replacement program.

William Andrew Hendricks -- President, Chief Executive Officer

So, John, that's a really good question. You might be a few weeks early in our budget process for us to be able to even answer that, but certainly what the teams look at is what we think our cost of ownership is in terms of some of that technology. We've been testing various technologies that's been available to us as you know and trying to understand what the cost is whether it is the fluid-end, the power-end, transmission, new engine, et cetera.

And so, as we do get into that budget process in the fourth quarter we will be looking at that, but I think it's really too early for us to have that discussion. But overall again we will be looking at the cost of ownership, rebuild versus buying new for a complete pump trailer, rebuild versus buying new for individual components, and all those kind of things as we get into the budget cycle for 2019.

John Daniel -- Simmons & Company International -- Analyst

Okay. Fair enough. Just two more from me. I suspect it's safe to assume that fleet profitability across your company varies. And so, when you move from 25 fleets to 21, are you able to specific idle your worst performing fleets or you're simply dropping the fleets that's impacted by a specific customer slowdown?

William Andrew Hendricks -- President, Chief Executive Officer

I would say that in the market that we have today, this is really a customer driven event. It's based on customers' budgets, customers' takeaway capacity in certain basins, and I would say as an industry we don't have a lot of optionality here on our side and that we really just have to kind of move with what the customers are doing and we have to respond to that as best we can and manage the cost side as we move into this fourth quarter. So, it's a bit of a challenging market knowing that we do have this activity slowdown in the fourth quarter driven by some customers more than others and yet there is the potential for accelerating activity again some time in 2019 and very likely in the first half of 2019 just because of visibility we have on the drilling side of the business.

John Daniel -- Simmons & Company International -- Analyst

Yes. Okay. I guess final one from me, you noted and customers have indicated the possibility they'll go back to work once they get new budgets. I'm just curious for those customers how would you characterize the price discussions? Are they trying to take advantage of lower prices now or do you tell them you need to pay a higher price for us to reactivate these fleets? Because you said in the release that you're not -- basically you're not going to work fleets at current market conditions. I'm just trying to understand as we think about Q1 into Q2, if we start modeling higher fleet counts should implicitly be assuming higher rev per fleet or would you put them back at current pricing?

William Andrew Hendricks -- President, Chief Executive Officer

I think those discussions are yet come. I think it will -- some of that will depend on our side on how those negotiations go and how fast activity in the industry is ramping up. And so, I think it's kind of too early to really know what that's going to look yet. From my standpoint, unfortunate we're slowing activity in the fourth quarter, unfortunate that we've had to shrink from 25 to 21. But as we increase activity in 2019, which we strongly feel like we will, we want to focus on the margin for spread pushing pricing were we can.

John Daniel -- Simmons & Company International -- Analyst

Got it. Okay. Guys, thank you for your time.

William Andrew Hendricks -- President, Chief Executive Officer

Thanks.

Operator

Your next question comes from the line from the line of Brad Handler with Jefferies. Your line is open. Please go ahead

Brad Handler -- Jefferies -- Analyst

Thanks for squeezing me in, guys. Actually, I was trying to unqueue. My questions have been answered, but thank you very much for the opportunity.

William Andrew Hendricks -- President, Chief Executive Officer

No problem. Thanks.

Operator

Your next question comes from the line of Daniel Boyd with BMO Capital Markets. Your line is open. Please go ahead.

Daniel Boyd -- BMO Capital Markets -- Analyst

Yes. Thanks. I think I'm down to question 20 on my list, but I will give it a shot. Given the focus that you guys have on cash and returns and really cutting things in pressure pumping during this period of weakness, I'm just wondering on those idle crews, are you able to use those at all or do anything to lower the repair and maintenance cost on the crews that you're working in this environment.

William Andrew Hendricks -- President, Chief Executive Officer

I would say that there is not, in terms of OpEx or CapEx spend for repair and maintenance, there is nothing that's going to shift what we have to spend on a per operating hour of usage for a piece of equipment in the fourth quarter. We are just going to try to manage what we can to keep the cost in line and not overspend in the fourth quarter.

Daniel Boyd -- BMO Capital Markets -- Analyst

Okay. And then how should we think about any reactivation cost on these fleets that you are idling when they come back to work in 2019?

William Andrew Hendricks -- President, Chief Executive Officer

We are going to take the opportunity on some of these spreads to just make sure that they are in condition to be able to be reactivated and I think that's just going to flow through the P&L over the next couple of quarters, so I don't think it's -- we've got some of that built into those projections on the OpEx side already.

Daniel Boyd -- BMO Capital Markets -- Analyst

Okay. Great. Thanks.

William Andrew Hendricks -- President, Chief Executive Officer

Thanks.

Operator

Your next question comes from the line of Kurt Hallead with RBC. Your line is open. Please go ahead. Kurt, your line is open. Pleaes go ahead. Kurt you maybe on mute. And we have no further questions at this time.

Mark Steven Siegel -- Chairman of the Board

Thank you. We like to thank everybody for joining us for Patterson-UTI's conference for the third quarter of 2018 and look forward to speaking with you as we report fourth quarter of 2018 in February. Thanks everybody.

Operator

This concludes today's conference call. Thank you for your participation. You may now disconnect. Have a good day.

Duration: 66 minutes

Call participants:

Mike Drickamer -- Vice President-Investor Relations

Mark Steven Siegel -- Chairman of the Board

William Andrew Hendricks -- President, Chief Executive Officer

Marshall Adkins -- Raymond James & Associates, Inc. -- Analyst

Sean Meakim -- JPMorgan Securities LLC -- Analyst

James Wicklund -- Credit Suisse Securities -- Analyst

James West -- Evercore Group -- Analyst

Marc Bianchi -- Cowen & Co. -- Analyst

Judson Bailey -- Wells Fargo Securities -- Analyst

Tommy Moll -- Stephens, Inc. -- Analyst

Chase Mulvehill -- Bank of America Merrill Lynch -- Analyst

Taylor Zurcher -- Tudor, Pickering, Holt & Co. Securities, Inc. -- Analyst

Blake Gendron -- Wolfe Research -- Analyst

Ken Sill -- SunTrust Robinson Humphrey, Inc. -- Analyst

Colin Davies -- Sanford C. Bernstein & Co. -- Analyst

John Daniel -- Simmons & Company International -- Analyst

Brad Handler -- Jefferies -- Analyst

Daniel Boyd -- BMO Capital Markets -- Analyst

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