Ladies and gentlemen, thank you for standing by, and welcome to Patterson-UTI Energy Fourth Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] I would now like to hand the conference over to your speaker today, Mr. Mike Drickamer. Thank you. Please go ahead, sir.

Thank you, Maddy. Good morning. And on behalf of Patterson-UTI Energy, I'd like to welcome you to today's conference call to discuss the results of the three and 12 months ended December 31, 2020. Participating in today's call will be 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 Andy Hendricks for some opening remarks. Andy?

Thanks, Mike. Good morning, and welcome to Patterson-UTI's fourth quarter conference call. We are pleased that you could join us today. For the fourth quarter revenues increased for the first time since the downturn began, driven by higher levels of drilling and completion activity. We are encouraged by the higher activity levels as the industry has begun a recovery. Based on our customer engagement, we are confident that activity levels will continue to improve. I will now turn the call over to Andy Smith, who will review the financial results for the fourth quarter. I'll then comment on our operational highlights as well as our outlook before opening the call to Q&A. Andy?

Thanks and good morning. For the fourth quarter, we reported a net loss of $107 million or $0.50 per share and adjusted EBITDA was $29.6 million. During the fourth quarter, we reduced gross debt by $66.2 million through the repayment of $50 million of our term loan and open market purchases of $16.2 million of senior notes. The open market purchases were made at a discount to face value, resulting in a $3.6 million gain that is reflected in our income statement as an offset to interest expense. The reduction in gross debt combined with an increase in our cash balance over the year produced our net debt during 2020 by $117 million to $684 million at the end of the year. After the repayments, we only have $50 million of debt remaining that comes due before 2028, which is easily covered by the $225 million of cash on our balance sheet at the end of the year. Capital expenditures during 2020 totaled $145 million. For 2021, we expect total capital expenditures of approximately $135 million, including $85 million for contract drilling, $30 million for pressure pumping, and the remainder spread among our other segments and general corporate purposes. CapEx in 2021 is primarily maintenance CapEx focused, while also allowing for technology investments and minor upgrades to our equipment to take advantage of the recovery and strengthen our position as a leader in technology and performance. Before I turn the call back over to Andy, for the first quarter, we expect SG&A expense of approximately $23 million. We expect depreciation, depletion, amortization and impairment expense of approximately $148 million. For 2021, we expect an effective tax rate of approximately 21%. Lastly, we will be paying our quarterly cash dividend of $0.02 per share on March 18, 2021 to holders of record as of March 4, 2021. With that, I'll now turn the call back over to Andy Hendricks.

Thanks, Andy. In contract drilling, our average rig count for the fourth quarter improved to 62 rigs from 60 rigs in the third quarter. The proportion of rigs that were idle but contracted decreased to 16% in the fourth quarter from the 28% in the third quarter. Our rig count improved to 65 rigs at the end of the year, of which five rigs were idle but contracted. Average rig margin per day during the fourth quarter was $7,770, which exceeded our expectation. Relative to third quarter, average rig revenue per day of $20,210 was negatively impacted by lower day rates in the absence of any lump sum early termination revenues in the fourth quarter. Average rig cost per day increased to $12,440 due primarily to a smaller proportion of rigs that were idle but contracted compared to the third quarter. At December 31, 2020 we had term contracts for drilling rigs providing for approximately $300 million of future dayrate drilling revenue. Based on contracts currently in place, we expect to average 42 rigs operating under term contracts during the first quarter, at an average of 34 rigs operating under term contracts for 2021. Looking forward, first quarter drilling activity is expected to improve averaging 69 rigs for the first quarter of which an average of five rigs are expected to be idle but contracted. With a small proportion of rigs that are idle but contracted during the first quarter average rig revenue is expected to increase to approximately $21,000 per day, an average rig operating costs is expected to increase to approximately $14,500 per day, also due in part to the reset of payroll taxes and rig reactivation expenses. Turning now to pressure pumping. We averaged seven active spreads during the fourth quarter, up from five active spreads in…

Yes, sir. [Operator Instructions] Your first question comes from the line of Sean Meakim with JP Morgan.

Thank you. Hey, good morning.

Good morning, Sean.

So Andy, sort of we can start talking about cash flow for a little bit. So the term loan paydown and the debt repurchase makes sense, we also consumed more cash than generated beyond that in the fourth quarter, that should be starting to ramp. Can we just, maybe – I think the CapEx guide also makes sense based on our activity assumptions. Could we just maybe talk about sources and uses of cash maybe at the end of the year and going into 2021? As we think about working capital maybe use of cash a little bit as activities moving higher, cash taxes even the best materials, any of the pieces that we should be thinking about on cash movement between now and the end of the year.

Yes. So we built a little bit of working capital in the fourth quarter, and that was really more of a timing issue more than something that I would say is – I do think as we go through 2021, we'll probably be a little bit higher in working capital, not significantly. We do always look at our, and again, because you talked about divestitures, we're not talking about any line of divestiture, but certainly we look at our portfolio of assets. And we're constantly looking at things that were selling whether they're properties or older equipment or things like that. So you'll see some cash from that. Cash taxes, I wouldn't expect much in the year. So really, we kind of always think about again in kind of a flattish working capital type environment an EBITDA less CapEx, and then interest expense with some of the non-cash items that are already embedded in EBITDA sometimes usually generally wash out. So that's kind of how we went in our free cash flow for the year.

That's really helpful. I think that makes a lot of sense. And then I wanted to touch on the lithium battery fleet and dual fuel optimized fleet. So we've put all that together, just looking to get some more granularity on the opportunity set there. So things like your – are you able to get a premium in the market for these? What is the fleet next look like today? I assume it's pretty low in terms of the batteries today, but dual fuel, how much does that make a little mix, the CapEx budget this year, does that account for any material dual-fuel conversions? Are we – I guess the net is also, is this a top line story in terms of making this a bigger piece of the fleet or is it really just about a bottom line being competitive in the market and doing some cases at a lower cost or lower capital expense?

I think for us it's a mixture of increased revenue, but also staying competitive and increasing market share. So when you look at dual-fuel, we do this on both drilling rigs and pressure pumping, all the drilling rigs, but we've had a number of our rigs kidded up for dual-fuel for years. Some customers use that optionality, some don't, but it's there on a number of our rigs already. So I don't anticipate that there is really any spin there on the CapEx side. In pressure pumping, we're one of the leaders in dual-fuel, we've been doing that for years, as I mentioned, one of the spreads we're moving from the Northeast to Texas is already kitted up for dual-fuel. But we will add some more dual fuel and pressure pumping, but it's already built into the CapEx plan. The real interesting story is the Ecocell and the lithium battery storage energy system that we have there, and how it can control the engines and auto switch off engines and control the loads on the various engines and balancing that out with the energy draw out of the lithium battery storage. And we have some – we have one working in the field today that we've been field testing and we've commercialized that system, we have another one that'll be in the field shortly, and we have battery orders to get us through the year to build what we expect will be a fairly strong demand of these. And I don't want to throw any numbers out yet, but we've already pre-ordered batteries to come in to be able to build these Ecocells, and that's built into the CapEx budget.

Just last thing there. Are you able to quantify that difference in terms of like, just let's say on a new bill fleet or something just to quantify what a traditional set looks like versus what this would look like just to level set for people?

Yes. I mean, the Ecocell is for the drilling rigs and so there is value for the operator there, when we're running that it reduces fuel consumption. And so – and there is a cost to build it, so we are able to charge to refute that cost and get a return on that investment when we add that to a drilling rig.

Great. Thank you.

Your next question comes from the line of Ian MacPherson with Company of Simmons.

Thank you. Good morning. I wanted to ask a couple of questions on your Q1 outlook, both for activity and for the components of your margin guidance. Your activity today on the website, 70 rigs. So you talked about activity is going to continue to improve, but your Q1 guidance looks like it's around where you are today. So I just want to get your thoughts on where you see the rate of improvement and the rig count? As we go through the quarter, do you feel like we're nearing a top or temporary top anyway, in a plateau from here or could there be some element of conservatism in that 69 rigs for Q1?

So, the way the math ends up on the 69 rig projection for Q1, yes, we're 70 on the website site right now, but we only averaged 67 in the first month of the quarter. So it's likely to be roughly flattish for the rest of the quarter, but it's not a top, not a plateau. It's just where the quarter is going to land. As we look forward for the rest of the year, I anticipate we'll be putting up more drilling rigs, but that's just where the quarter lands in terms of the math and the count on the projection.

Okay. Thanks, Andy. And then I think you said your day rate should be at $21,000 in the first quarter. So that would be – that will be up in the past couple of quarters. What's driving that? And then if we get better cost absorption after Q1 with the reactivation and payroll expenses that you mentioned that are pushing your costs up in Q1, is there – do you have some visibility toward a trough in cash margins in the first quarter and maybe some upside beyond Q1 or is it too early to necessarily call that?

So what we said on the last call was that, we thought that we would see a margin bottom for our business sometime around Q4, Q1. Our visibility right now is that this is likely Q1 and that we should see improving margins throughout 2021 based on not necessarily where WTI is trading today, but based on where WTI was trading earlier in the quarter. So I'm actually somewhat encouraged a little bit of be, and if WTI hold things where it is today, then there may be even a little more upside than the way we had viewed earlier in the quarter. But I would say that – like I said, our view is that Q1 is likely the bottom for margin and we should see some improvements in margins throughout the year from here.

That's great. Thanks, Andy. I imagine little bit of margin...

Yes.

Improvement would be there.

Ian, on your. Sorry, go ahead.

I was going to say, I assume that the average cost go down with better absorption as part of that calculus right?

They should over time. Yes. I would also say to your first part of your question about day rates coming up, that's almost entirely a mix issue as we have fewer idle but contracted rigs work included in our rig count in the first quarter relative to the fourth quarter.

Got it. Thank you, gentlemen. Appreciate it.

Sure.

Your next question comes from the line of Chris Voie with Wells Fargo.

Thanks. Good morning.

Good morning, Chris.

Maybe switching over to pressure pumping here for a minute. I guess, can you help us think about the impact that we are having in the having in the first quarter? If you would exclude that idle time, would there be more of an improvement in gross profit or can you help us maybe think about the exit rate in the first quarter? And maybe wrapped into that, has there been any improvement in pricing within pressure pumping so far this year?

I'll work backwards on that. There's certainly been no improvement in pricing and we don't anticipate any improvement in pricing in the first quarter. I think that as rig count continues to move up through 2021, there will be an opportunity to push pricing and pressure pumping later in the year. So we're somewhat encouraged there, but it just hasn't happened yet. Especially what we saw in overall industry activity levels in the fourth quarter in the Northeast, it came down fairly quick, it came down a significant amount. And as you know we have a strong presence up there in the Northeast, as well as we do in Texas. And so we made the decision and we're able to work with an operator in Texas and move one of our dual-fuel spreads out of the Northeast and into Texas. And the interesting thing for us is that dual-fuel and pressure pumping is primarily or historically been a Northeast phenomenon, because you're in the gas markets, but we're seeing more operators in Texas. We are trying to deal with the gas production that they have in their fields and consume it. Starting to look at and switch to dual-fuel in Texas. So since we have those fleets, we have that equipment, we're encouraged by that opportunity to be able to move that down there. But because of the decrease in industry activity in the Northeast and decrease in our activity, there is a lot of moving pieces in the numbers for both Q4 and Q1. So we're projecting that we're going to hold our spread count flat, and basically similar financials revenue and margin to Q1 is what we had in Q4 just because of the movement in activity. As I mentioned in earlier in the Northeast, we don't anticipate activity improving until the end of the first quarter, and that's just based on discussions with the customers.

Okay. That's helpful, thanks. And to my second question, I guess you have a lot of the large kind of private E&Ps in your customer base. It's a decent part of your customers, I guess. Do you have a view on activity going forward from here on a public versus private basis? Do you think it's pretty consistent or just like more growth from one group versus the other?

I think there is two components of it. I think one is the reaction time of the privates versus the publics and that will play out similar to what it did last year where the privates and the smaller publics can move faster than the large publics. The large publics have been slow to react and in some cases are still releasing rigs. And the privates and the smaller, more nimble publics have been moving quicker to reactivate rigs to grow activity in the numbers you've seen in the data, but also have discussions with us about what they want to do later in the year. So it's really the large publics that are moving slow in this process.

All right. Thanks for taking my questions.

Your next question comes from the line of Mike Sabella with Bank of America.

Hey, good morning, everyone.

Good morning, Mike.

Thanks for taking the call. I was wondering if you could just kind of start just second part of the pumping guidance a little bit more. Are you able to help us understand when that fleet starts working down in Texas? And then as we think about the Northeast kind of a percentage of what you are earning? Can you help us understand the magnitude of that business? And then if there are any costs to move that fleet down to Texas?

So the fleet will take approximately two weeks to move down to Texas from the Northeast from the time it leaves earning revenue in the Northeast to the time it starts earning revenue in Texas, and there is no real significant cost other than fuel and some component changes that we will make for the activity in the South versus the Northeast, but I would say overall costs are fairly minimal. We're certainly seeing a shift here lately in the amount of activity, not just us, but the industry where the Northeast was busier earlier in the year, busier in the third quarter and then had a big slowdown in the fourth quarter. And with us moving a spread then where we're down to a shift in mix, and so the majority of our work is going to be in Texas, and then we'll see how that plays out later in the year. But it's clear that gas operators in the Northeast are really trying to manage the gas market up there as best they can and not push too much gas into that market.

Got it. And then switching to rigs. I think in the press release it was a 34 rigs under contract this year. Can you kind of give us a split of what proportion of those were pre-COVID and what proportion were post-COVID?

I don't have that information off hand in terms of the timing of the contracts. I'd say a fair number were still pre-COVID. We're still going to see a roll-off of rigs that are pre-COVID. We've been signing some, but a mix of these – when you look at the rig fleet that we have today, it's a mix of prepayment contracts, contracts signed during COVID and then shorter term work that might be six months or less. So, it's a mix of all that today.

Got it. And is the term contracts that you all are getting today are those close to where spot is or is there any difference?

Can you say that again.

The term contracts you're getting today, are those close to where spot sits or are there – is there a difference between those two?

I would say the term contracts we're getting today are close to what the spot market is. When we sign rigs today on term contract, we're typically shy – signing as shorter term as we can negotiate, because we think there's upside later in the year.

Got it. Thanks for taking my questions.

Your next question comes from the line of Scott Gruber with Citigroup.

Yes, good morning.

Good morning, Scott.

So, there would be upturn in the market here. I imagine that customers don't want to lose the efficiencies that we've gleaned over the past 12, 18 months as happen historically. Those would reverse during the upturn. And my question is that obviously you have some more cash coming in the door. So, Andy, can you talk about your ability to potentially expand your ancillary services, your software and app sales within drilling or are those conversations starting to accelerate here?

Yes. And I would say that some of the successes that MS Directional is seeing in increasing their market share and growing faster than the rig count is due to the fact that we have a very large drilling contracting company that can open a lot of doors for that. So we're certainly seeing synergies from that. I don't want to take away from what they're doing at MS Directional, because they're doing a lot on their own and service quality is very high. Today, they're providing high level of efficiency for customers, but we're seeing more customers who look at our rig also look at MS Directional. And following on from that, they're looking at how can they layer in some of these interesting software services such as HiFi Nav, which is a – it's a software cloud services, it's remote operations, and has a lot of benefit in terms of wellbore placement and improving production. So, I would say, all these things are starting – we're starting to see more pull through from all these as we build out these levels of technology and connect the dots between the various services.

Got you. And then just turning to frac, are you starting to see any inflation in frac. I realized sand and any sand inflation will get passed on, the thing about trucking, chemicals, is there any inflation starting to creep back into the system on the frac side as you get going again?

I think the one area that stands out is trucking. It just seems to be harder to find drivers in the Permian, and so moving sand creates more challenges there from a trucking standpoint and there has been some inflation in the trucking costs.

And how quickly can you pass those on to the customer, do they receive that?

In a challenging market like we're in, I would say, the ability to move that is relatively slow only because operators today want us to quote the jobs with some of these costs all baked in. So we try to manage the contracts with the suppliers back-to-back at the same time. There may be times during certain contracts, it's a little more challenging. But I'd say for the most part, we try to manage it back-to-back.

Understood. Appreciate the color. Thank you.

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

Hey, good morning, and thank you. My questions are largely follow-ups, but I think they are important, so I'll ask them any way. First is on the pressure pumping side of the business. Clearly, there was some white space – quite a bit of white space on the calendar in Q4. Your average active spread count was up 40% sequentially with two extra spreads, but the revenues are much lower. And so clearly the day's work went up 40% sequentially. Can you help us understand what the utilization of – is for those seven active spreads as you define them? What that utilization look like in Q4? And then how many of those fleets are actually in the Northeast today or at least were in the Northeast in Q4, and how many of those rigs are going to be in the Northeast in Q1?

It changes a month-to-month, but I would say we definitely had a fair amount of white space in the calendar, mostly driven by the Northeast, but also few other customer-specific issues in the fourth quarter. So, I look at those as relatively transitory, but it ends up looking similar in the first quarter as well, because we are moving a spread down, because we're waiting on operators to pick up activity in the Northeast. If you were to try to quantify the white space in Q4, it's going to be roughly equal for us in Q1 because of all those factors. I don't know if that helps you out.

Yes, it does. And can you give us a breakout of where your spreads are located today, whether it would be Texas versus Northeast?

So, we've got two working in the Northeast with varying degrees of white space in the calendar and then the others are working in Texas.

Okay, thanks. And my follow-up is on the contract drilling side of the business. If I heard you correctly, it sounds like you expect the margins to bottom here in Q1 and there is some payroll taxes that negatively impact margins that will go away in Q2. But if that's correct, can you help us understand what's driving the margin bottom in Q1? Is it better fixed cost absorption that's going to drive most of that margin improvement over the course of the year or do you also expect the average dayrate that you report each quarter to be relatively flat if not having bottomed in Q1?

Yes. Let me clarify that. So, I think that EBITDA is bottoming for the company in the first quarter and then continues to improve through the year. We're still going to have some decrease in percent margin as a percentile as we have some rigs roll off pre-existing contracts, pre-COVID and into today's market. And so we'll speak – we'll see some decrease in percent margin, but overall, we should see growth in EBITDA from where we are today.

Understood. That makes sense. Thanks, guys.

Your next question comes from the line of Connor Lynagh with Morgan Stanley.

Yes, thanks. Just a higher level one for me here. We've seen a fair bit of activity on the pressure pumping side of the business in terms of your – some of your competitors consolidating or rolling up smaller competitors a few transformative deals. Generally speaking, we've kind of heard from you guys and others talking down the merits of land rig consolidation, but I guess my question is, with where we are today and the sort of prospects for CapEx growth in the U.S. E&P industry, why is that not more top of mind? What's your sort of thinking around the potential for consolidation there?

I think in the land rig business in the way we view it is when – and when we view the land rig business, we are looking at the super-spec APEX rigs that we operate. And so it's just not clear to us that you need a lot more consolidation. What we've seen historically is the rig count starts to move up, then pricing starts to move up, and I think that we'll see leading edge dayrates move up later in the year as the rig count moves up. So I'm not sure that the industry needs more consolidation the way other sectors of oilfield services need consolidation.

It's fair. I guess since we're on the topic of pricing, there were some comments in the press release of looking forward to pricing in the future. I take from your commentary, we haven't seen it yet. But could you maybe just characterize, I guess, there is sort of the push and pull of you – if you increase your volume, you absorb some better fixed cost and improve your margin that way, how do you guys think about the likelihood or the desire to raise prices versus spot rates for new term contracts?

We're definitely focused on margins and maximizing those margins wherever we can, whether it's the drilling rigs, it's pressure pumping or it's directional drilling et cetera. And so we're going to try to get some pricing power when we can. It's one of the reasons that we're still flat on frac spreads. We just don't see a need to add more capacity to the market. We'd like to see the pricing move up in the market before we try to push more frac spreads into Texas. And so we think that there may be an opportunity to move pricing up later in the year in pressure pumping, because that's where we need the most. And as I said in drilling, I think as the rig count moves up later in the year, there is an opportunity for the dayrates to move up from where they are at spot.

All right, fair enough. Thank you.

Thanks.

Your next question comes from the line of Vebs Vaishnav with Coker Palmer.

Hey, guys. Thank you for taking my...

Hey, Vebs.

Hey. So I want to make sure I understand it correctly. You guys are saying that EBITDA for the company drops in 1Q and then improves, but not specifically the land rig margins, is that fair?

Yes, that's fair. As I said, I think where we are in the way we look at 2021 and what could potentially happen is that EBITDA is bottoming in the first quarter, margin could still come down in terms of percent margin as rig – as it rolls off and then it could change later in the year depending on what pricing does and how many rigs we're operating.

Okay. If you think about broadly, how are you thinking about how the U.S. rig count moves from here? So, obviously 4Q was a pleasant surprise. We still have public guys who will add rigs. Can we talk about how much visibility you have and like how you see beyond 1Q? How the rig count could shape up?

Well, I think what's interesting when you look at the rig count is the number of rigs that are operating in the industry, the number of rigs that we're operating today is really based on where commodities were trading several months ago. So the activity that we have today is based on plans that were put in place two and three months ago and there has been a big shift in the commodity price. So that's going to change the cash flow for our customers, but we just haven't seen that move into actual activity and it will be several months before we do, but I'm encouraged based on where commodity prices are trading that rig count has the potential to move up later in the year.

Okay. And maybe switching to pressure pumping. Just if you think about holding the pressure pumping pricing flat for a moment. If we assume it's going to be flat, we saw like about $5 million to $6 million EBITDA per fleet in 3Q, and the decline in 1Q, but like at current pricing is that $5 million to $6 million EBITDA per fleet a fair way of thinking about your profitability on average?

Yes. I would say, when it comes to pressure pumping, it's really about trying to align with customers who can maximize the overall efficiency of the operation and maximize stages per month, stages per quarter. And certainly, we were challenged there in the Northeast and I think the whole industry was when activity came down at the magnitude that it did in the fourth quarter in the Northeast. And then we have this transitory situation where activity in the Northeast is still going to be low starting off in the first quarter or maybe pick up later in the quarter and then we're moving assets out of the Northeast into Texas. So there's a lot of things that are going on, but the real key is to try to find operators who can keep this equipment busy. There is a number of operators out there that are even struggling to be efficient in their own processes because of their own budgets, their own cash flow. They want to work on a certain number of wells and then they want to take breaks and that's not efficient for them, that's not efficient for us or the industry in general. And so as commodity prices have moved up and cash flow improves, I think there is an opportunity for operators to be more consistent with the work and that helps us and it helps the industry.

Got it. Thank you for taking my question, gentlemen.

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

Yes. Thanks. Good morning. I want to circle back on the game theory with respect to term contracts here for a second and maybe ask the question in a different way than some of the others. It was in commentary about you walk in the sort of duration possible to maybe capture some upside moving forward that makes it sound like maybe your customers aren't really willing to acquiesce to the pricing if – even if that meant blocking in longer term. So first of all, is that true? And then to get more term, is there a percentage pricing improvement that you kind of have locked in or you ideally like to see? And then if we stay in this gridlock, I can mean – are we just presumably going to see six month or shorter term in perpetuity until the rig count gets to a certain level. How do you think, I guess, about the elasticity of pricing and also term contract duration?

I think pricing is still competitive out there in all the services, including the drilling rigs. I think that we're all thinking that there is some upside, and I believe there is based on how commodity prices have moved over the last few months. And I think that operator cash flow will improve and then activity will translate to higher rig count. So I think there is upside. And so we don't want to get ourselves locked into too long. The discussion about how long we're willing to lock in a term, it's not just pure math. I mean, certainly we'd like a higher price if we're going to lock in, in term today for a longer period, let's say, a year or more, but it might be that it's with a particular strategic customer who keeps us busy there might be several reasons we might do that other than just a percentage increase over the price. So it's not just about the math, but in general, we're trying to keep the terms relatively short because we think we have some upside.

That makes sense. It was in commentary about the microgrids and maybe participation in renewable and smart grid build out over time. I would imagine that small, but can you give us an idea of what the opportunity set is here in the near-term and maybe if you have an idea of growth or TAM moving forward or is it just too nascent, lumpy and early to tell at this point?

I think it's – let's start with, it's small. It's not big dollars within the scheme of what we do. I don't think we know the full potential that's out there. The marine business has been interesting for us. We've been doing a number of various vessels over the years and this crew ship was one of the larger projects we've had and we're very pleased that the team was awarded this project. It shows the confidence that shipbuilders have in the types of systems that we can build and install on these vessels. So that's very interesting and this kind of award can lead to larger awards in that sector in the future. In terms of industrial microgrids, this is all new and fresh in the U.S. You see a little bit more in Europe, but this is something that's still pretty new and I don't think any of us can really project what that's going to mean or what that's going to mean for our Current Power division. But we do a lot of interesting things that are custom engineering for specific applications. And so our ability to customize differentiates us from some of the larger companies that we compete with here in North America. And so it's why we're in discussions with various companies on various projects today, because of our ability to tailor things based on the industrial projects.

Got it. And one more quick one, if I can sneak it in. So you have marked some upgrade capital here to dual-fuel. You have been a leader in that space for a long time. I'm wondering if you could help us think about maybe new build economics at this point? Even if you're not necessarily going to do it yourself, you have a good idea of what pricing looks like today to get a new dual-fuel spread 50k versus what it was a year ago and maybe comment on relative barriers to entry for those who aren't necessarily current in terms of next-gen frac technology? Thanks.

Yes. There is no new build economic today and anybody buying new equipment is just making a bet and a hope on the future because the economics just don't exist. So, there is certainly no point investing in a full frac spread right now or adding capacity to the market. I think there are small things you can do. You can do upgrades. You can add dual-fuel kits on engines you already own and those kind of things that can make sense, but full spreads, it's very difficult to justify economically.

Yes. If your question was around the cost of procuring that equipment, it has come down a little bit. Still, we don't believe that the market economics make sense for putting in new equipment.

Okay. That's helpful. Thanks, guys.

All right. Next question comes from the line of Waqar Syed with ATB Capital Markets.

Thanks for taking my call. Andy, could you talk about your drill pipe inventory. Are you buying drill pipe right now? You have enough inventory and when do you think you'll be in the market?

I don't want to get too many suppliers excited, but we're buying drill pipe. So the demand is there for us. It's a great rental business. It's part of our CapEx budget. There are good paybacks on that. So, yeah, we're actually adding drill pipe.

Okay, good. And then in terms of your maintenance CapEx for the drilling rigs and for pumping, could you maybe provide some guidance there, what's it running at on a per crew basis?

Yes. So on a per rig basis, we're still kind of in that $750,000 to $1 million range per rig, per active rig. And then on a per spread basis, we're at about $4.5 million per spread in pressure pumping, inclusive of fluid ends.

Okay. And fluid ends are running at what like a $1 million or so a year?

Yes. A little north of that, but not much. They have come down. We're doing a better job of maintaining them in the field and getting more useful life out of themselves. So our fluid end usage has come down some and so as our maintenance expense.

Now, are these numbers for pumping, especially are these sustainable numbers longer term or do you think this is more like a one year, 18 months kind of number and then it may go up?

No. We think they are sustainable. We should be at a relatively normalized type spend level per crew this year.

Okay. Andy, I know you love both of your major businesses, drilling and pumping, but just thinking of the second half, do you think which business grows more in terms of top line from the first half levels?

I think we will see, in our case, may be different than others, but I think we'll see our drilling rig business grow at a faster pace on the top line and that's a combination of activity and maybe the possibility of some pricing power later in the year. On the pressure pumping side, we're just very cautious about activating spreads. We want to see some pricing increase there before we really push activations on the spreads.

Okay. So, where do you want your EBITDA per crew to be before you would reactivate the crew. Right now, it looks like if you want to take out of the cost of fluid ends, there really isn't any EBITDA or – per crew.

Yes. It's – I mean, it's running pretty tight. It's still an oversupplied and challenging market today and so we'd like to see that move up a little bit from where it is. We want this business to be accretive. Our projections are that it's accretive for the year. So, we'll just continue to evaluate it on a case-by-case basis as we look at the various projects.

So, does it – the EBITDA per crew needs to be above maintenance CapEx for you to activate a crew?

Correct.

Okay. The minimum there, okay. And to get there, will you need price increases or just on utilization you can get there?

We can get there on utilization, because as I was explaining earlier with the slowdown in the Northeast in the fourth quarter and then that not increasing activity in the Northeast to later in the quarter, then there is some activity challenges there. So that's going to improve the financials when activity improves in the Northeast. So, we're – with the spreads that we're working, we're above the cost of – it takes to work these spreads, but we're certainly challenged by activity late in 2020. But when it comes to reactivation, there are some costs of reactivation and we want to make sure we cover those costs as well.

Yes. And then in terms of your hydraulic horsepower dedicated per crew, is that on average running around 50,000?

It's a little bit higher. You see us doing more work in the Delaware basin. So that consumes more horsepower in the Delaware.

Okay, great. Thank you very much. Thanks, Andy.

Thanks. Appreciated Waqar.

And your last question comes from the line of John Daniel with Daniel Energy Partners.

Hey, guys. Thank you.

Hey, John.

Just one question for now. The Northeast, just your visibility and you're exceeded recovering to the levels that ventures out in 2020, do you see it gone higher, just your thoughts there.

My discussions with operators in the Northeast lead me to believe that they're are concerned about the price of natural gas in terms of overproducing up there and negatively impacting it. And so they're trying to keep their activity levels in check. So they don't overproduce in the Northeast. I think a lot of what we saw in terms of Q3 going into early Q4 and activity levels was going back to wells that were in the inventory and bringing those online. When we look at the rig count in the Northeast and that's probably a better proxy for what's going to happen in completions, we see that the rig count is relatively flat. So we're not looking for a huge increase in activity in the Northeast. We do have some specific customers that will increase the activity with us later in the quarter, but our rig count projection out there is relatively flat.

Okay. And when they come back with a little bit more activity, does that necessitate reactivating a crew or is that filling – fill up the white space or moving a crew back from Texas [indiscernible] how you manage that?

It's really just filling in white space and then we'll be busier on a stage per month basis.

Got it. Thank you for including me.

Thanks.

And there are no further questions at this time.

All right. Well, we want to thank everybody for joining us today. And again, we want to thank all the employees of Patterson-UTI for all the great work they're doing, and we'll see you next quarter. Appreciate it.

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