Patterson-UTI Energy Inc (PTEN) 2018 Q3 法說會逐字稿

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, Inc. Third Quarter 2018 Earnings Conference Call. (Operator Instructions) Thank you. Mike Drickamer, Vice President, Investor Relations, you may begin your conference.

Thank you, Emily. 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 3 and 9 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 statements. The company's SEC filings may be obtained by contacting the company or the SEC and are available through the company's website and through the SEC's EDGAR system.

Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company's press release issued prior to this conference call.

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

Thanks, Mike. Good morning and welcome to Patterson-UTI's conference call for the third quarter of 2018. We are pleased that you can join us today. This morning, I will turn the call over to Andy 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 is $65.9 million of noncash pretax 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 a total price of $50 million. This brings our total repurchases for the year 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 $0.04 per share, which resulted in an additional $8.7 million returned to 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 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.

Thanks, Andy. In contract drilling, our rig count during the third quarter averaged 178 rigs compared to 176 in the second quarter. The 2-rig sequential increase was less than we expected as opportunities to increase our Canadian rig count did not materialize. Our U.S. rig count during the third quarter matched our expectations as the U.S. market for super-spec rigs remained strong.

With strong demand for super-spec rigs, average rig revenue per day for the third quarter was higher than we expected, with a $410 sequential increase to $22,280. Average rig operating cost per day was in line with our expectations at $13,810. Accordingly, average rig margin per day increased during the third quarter by $200 to $8,470.

At September 30, we had term contracts for drilling rigs providing for approximately $825 million of future day-rate drilling revenue. This is a sequential increase of more than 20% in one quarter compared to our backlog at June 30 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, and an average of 81 rigs operating under term contracts during the 12 months ending 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 2 additional rigs with major upgrades later in the fourth quarter and 2 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 towards drilling deeper wells with longer laterals. By replacing the original mass and substructure, which collectively are commonly referred to as the center section of the rig, with a new center section rated for a 750,000-pound hook load, we can upgrade these rigs to the specification of a 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 components, 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 U.S. 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 and 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 that super-spec drilling activity will continue to grow, rates will continue to rise and average contract durations will lengthen. For the fourth quarter, expected 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 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 of 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 spreads. Despite deteriorating market conditions during the third quarter, revenues and gross profit were both better than we expected as we filled 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 and white space on the calendar for the fourth quarter. With this uncertainty, we plan to manage our headcount in 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 [so we'll 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 increasing super-spec drilling rig activity continues to drive the drilled but uncompleted well count, or the DUC counts higher. The increase in the DUC count should accelerate over the coming months, given the year-end slowdown in completion activity as operators slow their work to remain within budget. A drawdown in the DUC count in 2019, as operators complete wells to fill incremental pipeline capacity, would 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 in 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 third quarter compared to $52.7 million for the second quarter. Directional drilling gross margin as 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 did 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 that increasing repairs and maintenance expense is a prevalent challenge across the directional drilling industry today. The increasing wear and tear from higher drilling intensity, including high-pressure circulating systems of modern super-spec drilling rigs, is harder on downhole directional drilling equipment, leading 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 Rentals, Warrior Rig Technologies and 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.

Thanks, Andy. Fundamentals remain strong for U.S. 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 cause the growth rate and 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 a 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 underinvestment 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 accounts for approximately 2/3 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'd 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 super-spec drilling activity should remain strong.

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 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 for questions.

(Operator Instructions) Your first question comes from the line of Marshall Adkins with Raymond James.

Your frac business this quarter has meaningfully outperformed most all of 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? I know you brought the count down a little bit, which probably helped 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 '19 recovery for pressure pumping? Or do you think it happens sooner? So those are my 2 questions.

So thanks for the question. In terms of pressure pumping and what we were 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 were 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 rightsized 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 a 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. It was a lot of basic blocking and tackling in the pressure pumping business, just to try to make sure that we were rightsized as we worked 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.

Just a quick follow-up there. Were those spot or dedicated fleets where you were actually able to fill the white space? I assume it's spot market, but just out of curiosity.

Yes. Filling white space right now is basically just picking up spot work and inserting it where you may have delays or breaks in your current schedule. And those delays or breaks could be in 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.

Go ahead.

Marhsall, 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 that DUC count is probably going to increase during the fourth quarter as E&P's delay completions for various reasons. We feel that they're going to want to complete those wells early in 2019. And so exactly timing of the particular day, month, year they do that, is hard. But we think it's definitely a first half 2019 kind of prospect.

Your next question comes from the line of Sean Meakim with JP Morgan.

So 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 do you think it takes for activity -- for pumping activity to get back to 2Q, 3Q type of levels? And when it does, it is fair to say that, given some of the operational challenges you all had earlier in the year, that you'd expect to be able to get your profitability higher [or in natural] environment compared to what you delivered say in 2Q '18?

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 that 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 a higher commodity price, as we discussed. You also have some of the takeaway capacity in the Permian continuing to improve. And the budget issues aren't limited to the Permian. That's across the U.S. onshore. But of course, as the takeaway capacity improves as well, you're going to get enough to lift in completion as operators prepare for that increased takeaway in advance.

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

Yes, 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. We do think it's about trying to maintain a profitability per spread in pressure pumping.

And I just--I'm thinking about capital allocation for next year, can you maybe just walk us through how you think about prioritization of cash uses? And directionally, do you think CapEx will be higher or lower? You got of course the upgrade potential that you see continuing to unfold, but then perhaps reactivation is something that -- [function -- something that] CapEx been on the pumping, so 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.

I guess the response that I'd like to give is that we set our capital budgets in late December, [set our] operating and capital budgets in late December. And we feel that, by doing so at that time, we have the sort of maximum visibility into 2019 that a company could have. We typically have followed a rule of announcing our plans for capital expenditures in -- on our call in February as we announce 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've returned substantial amounts of capital to the investors already through 3 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 me 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.

Your next question comes from the line of James Wicklund with Credit Suisse.

Mark, on the statement, on the comment of returning cash to shareholders, you guys obviously aren't any better at timing the market than 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 it back as it gets cheaper? What's the methodology that you guys have for deciding to buy stock, buyback stock?

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 3 quarters so far -- during this year. And we've done so kind of in a [belt] regular program that has been varied 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're facing in which is 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 latter 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.

No, no. And I'm not arguing that you could. Like I say, the company's not doing any better than us. And it's not that it's been episodic. I'm just saying there's several different options. One is regular, a stated one as episodic. And one is just you decide to buy it back, and it seems to be the latter. You bought back stock 3 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 you can buy your stock tomorrow?

Jim, I guess I wish it was a 2-factor decision, but it's a multiple-factor decision. We're 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. Amount of 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 could include what they think, or what we collectively think is the right approach for the next quarter and then execute it.

Jim, I'll add that when it comes to running the business, we're really focused on trying to maintain capital discipline, especially around capital expenditures, whether it's maintenance and trying to be smarter about how we spend on maintenance, or on the growth side where we're trying to derisk dollars that we're investing into growth CapEx and minimizing that in the history of the company as returning 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.

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 stock price. That was really my only point. My follow-up, if I could -- I'm sorry, go ahead.

Like I said, it's certainly a function of what we believe our free cash flow is after CapEx during a given quarter as well.

Okay. My follow-up, 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 costs this quarter, and that puts you at 13%. But 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?

I think it's safe to say that yes, we are behind plan. It hasn't been generating the margins that we've been aiming for in 2018. We're still working with the management teams to make every effort to improve that. There's efforts underway to improve the operating costs to run some of this equipment in the harsher environment that we're dealing with the super-spec rigs. We're also going to make every effort to push pricing as the rig count continues to improve as well.

Can you get to 20% margins without price?

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 we're working on it.

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

I wanted to focus on the main driver here of earnings, and 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. 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 in inventories, so that when they do hit go on contracts, you can get out there quickly?

Yes, James. And as you know, as we look at these major upgrades, with the investment it takes to do this, we want to derisk these dollars with the long-term contracts to be able to do this at good day-rates. It gives us 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 up using those to upgrade rigs, we'll hold them as spares. These are not large dollars compared to the overall budget, but we do want to stay slightly ahead on the long lead items. But we wouldn't build a rig on spec or upgrade a rig on spec.

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 the last year or 2? I mean, is it like 10 or 15 per year or so?

Well, we mentioned that we have 2 to deliver in early 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 2 major upgrades that 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.

Your next question comes from the line of Marc Bianchi with Cowen.

Following on the upgrade conversation, you've got these 4 more rigs that are going into the market here in the fourth and first. What kind of contracts term do these rigs have? And what do the payback periods look like for the upgrade investment you've done?

Yes, so for the 4 major upgrades that we announced on the Q2 earnings call, we said that we signed contracts for 4 years for each of those rigs, and that the payback period based on those day-rates and margins is within that 4-year period of those contracts. So those -- 2 rigs that are being delivered at the end of this year and 2 rigs delivered in early 2019.

Okay, and when you calculate that payback, that's on the -- is that on the total margin? Or is that on the additional margin that you're getting because of the upgrade investment you're making?

I guess we don't separate the 2. We look at it in terms of the day-rate that we're getting on the rig for that upgrade, and what that payback has been based on the cash spent.

Okay. And then as you look at opportunities beyond these 4, would you say that they would be similar with that 4-year term in payback? Or are you seeing things evolve differently?

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 and good day-rates in order to do more of these upgrades and finish some more of these rigs.

Got it, okay. Maybe if I could just ask one more on the pumping side. The fleets now, you've got 21 in the field and 4 that you've put on the sidelines. Given what you see here over the next quarter or 2, 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 have in the field right now, maybe how much white space there is to be absorbed as activity comes back up.

So we plan to operate 21 spreads during the fourth quarter based on the 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 predict. That continues on likely into the first quarter, but at the same time, you get some budget resets from the customers. And we are already in discussions with some customers who want to restart early in the fourth quarter. So we certainly intend to hold on to 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 to make sure that we're maximizing that as we activate in an upturn in 2019.

Your next question comes from the line of Jud Bailey with Wells Fargo.

Follow-up there on pressure pumping, if I could. If I look at the revenue guidance and the gross profit guidance, I kind of back into a decremental that's probably in the mid-20s. I think I'm doing the math right. And if I am correct, what are the drivers to keep decrementals at such a readable 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're 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 kind of what you're suggesting from a decremental margin standpoint for the fourth quarter?

As we worked our way down in the third quarter from 25 to 21, we were 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's various moving parts that are in there.

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

For the most part, our spreads are working dedicated crews 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, we're not seeing that pressure right now.

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

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 up maintenance CapEx spending. So we'll just have to get back to you later on that.

Your next question comes from the line of Tommy Moll with Stephens.

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 apiece CapEx to perform the upgrade? And then for those that are active, is it a similar level of CapEx or a lower level?

So Mike's pulling up 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're a relative fit for the market. But some of those that are currently working, Mike just gave me the numbers. So we have 32 of the 53 that are idle. But the ones that are currently working may only need to add a [locking] system. They may need to add a high-pressure circulating system. So you're talking about a $1 million to $5 million investment there, depending on the rig. The ones that are idle may need 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, we see that continuing into 2019, and we're very upbeat about the drilling business.

Is it fair to assume that the next batch of upgrades are most likely to come from the idle stack, and that 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 an 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 are already generating a pretty good margin, and therefore might need more incentive on the pricing side to perform the upgrade. Is that fair?

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

Your next question comes from the line of Chase Mulvehill with Bank of America Merrill Lynch.

I guess the first question, just kind of keeping on the land rig theme. I was surprised to not to see any new upgrades 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, the lower number of bids out there today?

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 necessary that a customer goes out to bid and gets pricing. It's more of a discussion, which is positive because we're talking about operators entering in the long-term contracts at what we consider 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' budgets cycle. The operators are working on their budgets right now. And so when you get to the drilling department level of an operating organization, they likely don't have internal approvals yet to discuss further the further rig adds. Although we're in discussion of what their potential plans are for next year, they've got to get through their budget cycle before the drilling departments have that level of approval. And so I don't think we're going to hear -- we're not going to hear more definitive information from the operators until later in this year and 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 line.

And if somebody were to come to you today and wants you to upgrade, a major upgrade on one of your rigs, when would you be able to deliver it?

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

All right. And then the gross margin per day was guided to be up $500,000 a day. What's the OpEx component of that? Is OpEx kind of flat? Or is that going to be down?

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

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

So what or seeing in terms of leading edge, and we said this at the last quarter, that 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're 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-20 level.

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

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

Great. If you squint at those 2 day-rates that have a differential, has it narrowed?

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

Your next question comes from the line of Taylor Zurcher with Tudor, Pickering, Holt.

Andy, for the 4 spreads that you stacked during Q3, could you give us some color us to which basins and plays those spreads were previously working? And maybe more high level, as we think about the 4 primary geographics regions you operate in pressure pumping, those being Eagle Ford, Permian, Northeast and MidCon. Are you seeing similar softness across all 4? Or is the softness more acute in one versus the other?

So in terms of spreads that we're not marketing today, that softness was really around Texas and Oklahoma for the most part. But I think as we discussed, we have the potential for recovery in 2019 because we're not seeing the drilling rig count slow down. On the contrary, we're 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?

That answered it. I was 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 and sort of the spot market, what the delta is in pricing between spot market today versus some of your dedicated pricing today.

In terms of the delta and the pricing between what we're getting on dedicated and what we fill gaps [in the calendar 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's a lot of competition there. And that's a bit more challenging. But we're very pleased to see that pricing is essentially holding up with the dedicated agreements that we have.

Your next question comes from the line of Blake Gendron with Wolfe Research.

I'm 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 is maybe lateral lengths are starting to stagnate 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 that you play in both markets, what you're seeing at the field level on both sides? And maybe how does that follow through to the DUC count moving forward?

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 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're also continuing 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 continue to see the shift past 2019. So we'll have to wait and see how much gets consumed there. But again we are seeing that, and it's been driven by that shift to the zippers. So we'll have to wait and see some commentary on E&P on how that moves for the rest of the year.

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 and that market improving, do you see the same number of nameplate active spreads going back to work? Or are you going to have to add incremental horsepower to beef up those spreads? Or perhaps are you going to rationalize horsepower and consolidate to a fewer number of spreads?

So I think the rationalization on our side, you've heard in the third quarter when we dropped from 25 to 1. But at the same time, as we move into 2019, as we do reactivation, if those reactivations for a 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're 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.

(Operator Instructions) And your next question comes from the line of Ken Sill with SunTrust Robinson Humphrey.

So just wanted to ask a 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?

We're not calling it out right now. I mean it's moving depending on where these spreads are working. Even the spread -- even the 21 spreads that we're working in the fourth quarter, if we're doing -- we might be working on one type of pad where it's non-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.

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?

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

Okay. And then just kind of parsing into the slowdown, you guys are looking at a 20%, 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."

It's a mix of all of 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're 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're doing that through seasonality, through slowing down at holiday periods here as we get towards the end of the year, et cetera. But we recognize there's capacity constraints in the Permian, but we're seeing pullback across the U.S., not just the Permian, and a lot of that has to do with budget constraints.

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

So in the fleets, 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.

Your next question comes from the line of Colin Davies with Bernstein Research.

Just a question around what you've done around some of the variable costs for the idled frac fleet. Obviously if you're talking about reactivations in the first quarter or early in the year, there may be a different strategy than if it's more related to Texas and perhaps a Permian ramp in second half of '19. Can you just perhaps give a little more color on perhaps the people side and the variable costs?

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 costs in line. We do have turnover in this industry. That's not something that's just Patterson-UTI-specific, but the industry has headcount turnovers that's still relatively high. The job markets are tight across the U.S. So we can allow the turnover to bring our compensation costs down. But at the same time, we want to hang onto experienced personnel because we do believe that we have upside in 2019, and we believe it will be reactivating the spread at some point in 2019. So we're doing different things to manage that cost and the spending, but some of it is around headcount.

And I was just intrigued by your comments around directional. Just wondered whether there's perhaps any thoughts around whether there's a more structural pricing problem? I mean obviously, the massive increase in the drilling efficiency over the last few years makes it 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's mechanisms for pricing for directional services?

Now 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 it really depends on how we have to be able to manage the risk and 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 that pricing needs to come up in the directional drilling sector. With the super-spec rigs out there with 7,500 PSI circulating system, the blow rates are much higher. So the wear and tear on the downhaul equipment and 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 increase in percentage of super-spec rigs across the industry.

Your next question comes from the line of John Daniel with Simmons and Company.

Andy, if 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 new-build/replacement program?

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 technology that's been available to us, as you know. We're trying to understand what the cost is, whether it's the fluid in, the power and transmission, new engine, et cetera. And so as we go 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 kinds of things as we get into the budget cycle for 2019.

Okay, fair enough. Just 2 more for me. I suspect that it's safe to assume that fleet profitability across your company varies. So when you moved from 25 fleets to 21, are you able to specifically idle your worst-performing fleets? Or are you simply dropping the fleet that's impacted by a specific customer slowdown?

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 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's the potential for accelerating activity again sometime in 2019 and very likely in the first half of 2019, just because of the visibility we have on the drilling side of the business.

Yes, okay. I guess final one for 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 we implicitly be assuming higher rev per fleet? Or would you put them back at current pricing?

I think those discussions are yet to come. I think it will -- some of that will depend, on our side, on how those negotiations go and how fast the 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 like yet. From my standpoint, unfortunate we're slowing activity in the fourth quarter. Unfortunate that we've have 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 per spread, pushing pricing where we can.

Your next question comes from the line of Brad Handler with Jefferies.

Actually, I was trying to un-queue. My questions have been answered, but thank you very much for the opportunity.

Your next question comes from the line of Daniel Boyd with BMO Capital Markets.

I think I'm down to question 20 on my list, but I'll give it a shot. Given the focus that you guys have on cash and returns and really cutting things and 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 costs on the crews that you're working in this environment?

I would say that there's not -- in terms of OpEx or CapEx spend for repair and maintenance, there's 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're just going to try to manage what we can to keep the costs in line and not overspend in the fourth quarter.

Okay. And then how should we think about any reactivation cost on these fleets that you're idling when they come back to work in '19?

We're going to take the opportunity on some of these spreads to just make sure that they're 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.

Your next question comes from the line of Kurt Hallead with RBC.

And we have no further questions at this time.

Thank you. We'd 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 2018 in February.

Thanks, everybody.

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

Have a good day.