Ladies and gentlemen, thank you for standing by, and welcome to the Patterson-UTI Energy fourth quarter 2020 earnings conference call. At this time all participants are in listen-only mode. After today's presentation, there will be a question-and-answer session. To ask a question during the session, you need to press star one on your telephone. If you require any further assistance, please press star zero. I would now like to hand the conference over to your speaker today, Mr. Mike Drickamer. Thank you. Please go ahead, sir. Thank you, Maddie. 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 31st, 2020. Participating in today's call will be Andy Hendricks, Chief Executive Officer, and Andy Smith, Chief Financial Officer. A quick reminder of 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. Now it's my pleasure to turn the call over to Andy Hendricks for some opening remarks. Andy? Thanks, Mike. Good morning. 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 comment on our operational highlights as well as our outlook before opening the call to Q&A. Andy? Thanks. Good morning. For the fourth quarter, we reported a net loss of $107 million, or $0.50 per share. 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, reduced 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 18th, 2021, to holders of record as of March 4th, 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 idled but contracted decreased to 16% in the fourth quarter from 28% in the third quarter. Our rig count improved to 65 rigs at the end of the year, of which five rigs were idled 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 and 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 31st, 2020, we had term contracts for drilling rigs providing for approximately $300 million of future day rate drilling revenue. Based on contracts currently in place, we expect to average 42 rigs operating under term contracts during the first quarter and 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 smaller 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, and average rig operating cost 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 the third quarter. Pressure pumping revenue for the fourth quarter increased to $79.5 million from $72 million in the third quarter, while gross margin decreased to $4.1 million. While industry completion activity in the Permian increased during the fourth quarter, in the Northeast, where we have a strong presence, industry completion activity decreased significantly and remained at this lower level as we entered the first quarter. As a result, we are relocating one of our dual fuel spreads from the Northeast to Texas, where it has dedicated work. We expect low utilization of our active frac spreads in the Northeast until later in the quarter, when the plans of our customers suggest increasing activity. We expect to average seven active spreads during the first quarter, including the spread that will be idle for a period of time while moving to Texas. Despite lower activity levels in the Northeast, pressure pumping revenue and gross margin in the first quarter are both expected to be similar to the fourth quarter. Looking forward, we are encouraged by the increase we have seen in the rig count and expect we will see further growth in completion demand. Turning now to directional drilling. Revenues increased 64% during the fourth quarter to $16.9 million, outpacing the growth in the horizontal and directional rig count during the quarter, as we continue to gain market share in this business. The market share increase was aided by the enhanced performance of our new technology, the Mercury Measurement While Drilling System, and the new Impact Directional Drilling motor sizes, which were introduced in early 2020. With better fixed cost coverage and the benefits of the cost reduction efforts implemented in 2020, gross margin improved in the fourth quarter to $2.2 million, or 12.8% of revenues, from $500,000, or 5% of revenues, in the third quarter. For the first quarter, we expect directional drilling revenue to increase approximately 15% to $19.5 million, with gross margin of approximately $2.2 million. Turning now to our other operations, which includes our rental, technology, and E&P businesses. Revenues for the fourth quarter were $8.9 million, with a gross profit margin of approximately 10%. For the first quarter, we expect other operations revenues to improve to approximately $10 million, with a gross profit of approximately $2 million. Our other operations include the technology division, Current Power. This electrical engineering and controls division continues to broaden its customer base into other sectors, such as marine and industrial microgrid. Marine products are now growing to be the largest portion of this business. As an example of the type of projects, we are in the process of completing the delivery and installation of the full electrical controls for the propulsion system of the first new cruise ship built in the U.S. in recent years. Our team has experience in products for microgrid controls in various industrial applications, and we expect demand in this sector to continue to grow along the expanding renewables and smart grid electrical systems industry. The start of a recovery is an encouraging time in the oil field, and especially at Patterson-UTI. Like the rest of the industry, we are looking forward to increased activity levels and bringing back more employees, and we are also encouraged that we are coming out of this downturn stronger than before, similar to how we have emerged stronger from every other downturn in the company's history, with improved liquidity, reduced debt, and a greater technology position. We are very well positioned, both financially and operationally, and our investments have made us a leader in technology and performance. In 2020, we reached several technology milestones from which we expect to benefit during the recovery. First, we strengthened our position as a leader in alternative fuel technology with the commercialization of our EcoCell lithium battery hybrid energy management system. This unit is capable of efficiently displacing one of the gen sets on a rig to reduce both fuel consumption and emissions. The value of this technology is maximized when used in combination with our CORTEX power management system and our dual fuel engines, as the natural gas substitution rate can be optimized. With an increasing interest among customers in ESG solutions, we are very excited about this technology. We also commercialized our CORTEX Key data analytics device in 2020. This edge server device, installed at the well site, allows for the streaming of high-frequency data, which can be combined with the analytical power of our PTEN+ Performance Center to drive informed decisions and improve efficiency. We commercialized our remote measurement while drilling operations during 2020 and have started to build significant experience with 69 wells or more than one million feet of well bore drilled using remote MWD operations with a more efficient cost of service delivery. We also commercialized our cloud-based and remote operation HiFi Nav well bore placement service in 2020, including automated data transfer from the well site. HiFi Nav is a one-of-a-kind algorithm for improving the knowledge of the well bore position while drilling both horizontally and vertically, thus reducing geological uncertainty in real time. In 2021, we expect to commercialize our cloud-based HiFi Guidance, which takes the output of HiFi Nav, as well as geo-steering target changes, and calculates steering decisions to ensure the well bore stays within the producing zone while optimizing rates of penetration. We have several other exciting technologies that we're actively working on, are excited to bring to the market in 2021. With that, we would like to thank all of our employees for their hard work and valiant efforts through a very challenging time, both in our industry and in general. Maddie, we would now like to open the call to questions. Yes, sir. As a reminder, to ask questions, you will need to press star one on your telephone. To withdraw your question, press the pound key. Your first question comes from the line of Sean Meakim with JPMorgan. Thank you. Hey, good morning. Morning, Sean. Andy, I was hoping we could start talking about cash flow for a little bit. The term loan pay down and the debt repurchase makes sense. We also consume more cash than we generated beyond that in the fourth quarter. That should be starting to ramp. 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 as of the end of the year and going into 2021. As we think about working capital, maybe a use of cash a little bit as activity's moving higher, cash taxes, even divestitures. Any other pieces that we should think about on cash movement between now and the end of the year? Yeah. 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 a trend. 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 again, because you talked about divestitures, we're not talking about any line of divestiture. Certainly, we look at our portfolio of assets, and we're constantly looking at things that we're selling, whether they're properties or older equipment or things like that. You'll see some cash from that. Cash taxes, I wouldn't expect much in the year. 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 wash out. That's kind of how we look at our free cash flow for the year. That's really helpful. Yeah, I think that makes a lot of sense. I wanted to touch on the lithium battery fleet and dual-fuel optimized fleets, so we put all that together. Just looking to get some more granularity on the opportunity set there. Things like. Sure are you able to get a premium in the market for these? What does the fleet mix look like today? I assume it's pretty low in terms of the batteries today. Dual fuel, how much does that make of the mix? The CapEx budget this year, does that account for any material dual fuel conversions? 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, in some cases, 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. When you look at dual fuel, we do this on both drilling rigs and pressure pumping. On the drilling rigs, we've had a number of our rigs kitted up for dual fuel for years. Some customers use that optionality, some don't. It's there on a number of our rigs already, so I don't anticipate that there's 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. 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. We have one working in the field today that we've been field testing, and we commercialized that system. We have another one that'll be in the field shortly. We have battery orders to get us through the year to build what we expect will be a fairly strong demand of these. 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 just, let's say, on a new built fleet or something just to quantify what a traditional set looks like versus what this would look like, just to level set for people? Yeah. The EcoCell is for the drilling rigs. There is value for the operator there. When we're running that, it reduces fuel consumption. There's a cost to build it. We are able to charge to recoup that cost and get a return on that investment when we add that to a drilling rig. Great. Thank you. This question comes from the line of Ian Macpherson with the 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 is 70 rigs. You talk about activities continuing to improve, but your Q1 guidance looks like it's around where you are today. Just wanted to get your thoughts on where you see the rate of improvement in the rig count. As we go through the quarter, do you feel like we're nearing a top, or a temporary top anyway, and a plateau from here? Could there be some element of conservatism in that 69 rigs for Q1? The way the math ends up on the 69 rig projection for Q1, yes, we're at 70 on the website right now, but we only averaged 67 in the first month of the quarter. 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's 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. I think you said your day rate should be at $21,000 in the first quarter, so that would be up from the past couple of quarters. What's driving that? 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, do you have some visibility towards a trough in cash margins in the first quarter and maybe some upside beyond Q1, or is it too early to necessarily call that? 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. I'm actually somewhat encouraged, a little bit upbeat, and if WTI holds where it is today, then there may be even a little more upside than the way we had it viewed earlier in the quarter. 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. Yeah, Ian. improvement would be good. Ian, Sorry, go ahead. I was going to say, I assume that the average costs go down with better absorption as part of that calculus, right? They should over time. Yeah. I would also say to your first part of your question about day rates coming up, that is almost entirely a mix issue as we have fewer idle but contracted rigs included in our rig count in the first quarter relative to the fourth quarter. Got it. Thank you, gentlemen. I appreciate it. Sure. Your next question comes from the line of Chris Voie with Wells Fargo. Thanks. Good morning. Good morning, Chris. Maybe switching to pressure pumping here for a minute. I guess, can you help us think about the impact that's having in the first quarter? If you were to 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. We're somewhat encouraged there, but it just hasn't happened yet, especially with 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. 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 were able to work with an operator in Texas and move one of our dual fuel spreads out of the Northeast and into Texas. The interesting thing for us is that dual fuel and pressure pumping has primarily, well, historically been a Northeast phenomenon because you're in the gas markets. We're seeing more operators in Texas who 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. Since we have those fleets, we have that equipment, we're encouraged by that opportunity to be able to move that down there. Because of the decrease in industry activity in the Northeast and decrease in our activity, there's a lot of moving pieces in the numbers for both Q4 and Q1. We're projecting that we're going to hold our spread count flat and basically similar financials revenue and margin to Q1 as what we had in Q4, just because of the movement in activity. As I mentioned 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. For my second question, I guess you have a lot of large kind of private E&Ps in your customer base. It's a decent part of your customer base, 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 do you expect more growth from one group versus the other? I think there's two components of it. I think one is the reaction time of the privates versus the publics, that'll 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, in some cases are still releasing rigs. 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. 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. Thanks for taking the call. I was wondering if we could just kind of start just pick apart the pumping guide just a little bit more. Are you able to help us understand when that fleet starts working down in Texas? As we think about the Northeast, kind of a percentage of what you all are earning, can you help us understand the magnitude of that business? If there are any costs to move that fleet down to Texas. 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. There's no real significant cost other than fuel and some component changes that we'll make for the activity in the South versus the Northeast. 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. With us moving a spread, then we're down to a shifting mix. The majority of our work is going to be in Texas, and then we'll see how that plays out later in the year. 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. Switching to rigs, I think in the press release it was at 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 offhand 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, which 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 pre-COVID contracts signed during COVID, and then shorter-term work that might be six months or less. It's a mix of all that today. Got it. 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 is there a difference between those two? I would say the term contracts we are getting today are close to what the spot market is. When we sign rigs today on term contract, we are typically signing as short a term as we can negotiate because we think there is 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. Good morning, Scott. With the upturn in the market here, I imagine that customers don't want to lose the efficiencies that they've gleaned over the past 12, 18 months, as happened historically, those would reverse during the upturn. Now customers obviously have some more cash coming in the door. Andy, can you talk about your ability to potentially expand your ancillary services, your software and app sales within drilling? Are those conversations starting to accelerate here? Yeah, 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. 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. The service quality is very high today. They're providing high levels of efficiency for customers. We're seeing more customers who look at our rigs also look at MS Directional. 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 software cloud service that's remote operations and adds a lot of benefit in terms of well bore placement and improving production. I would say 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. Just turning to frac, are you starting to see any inflation in frac? I realize any sand inflation will get passed on, but think about trucking or chemicals. Is there any inflation starting to creep back into the system on the frac side as we 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. So moving sand, it creates more challenges there from a trucking standpoint. There's been some inflation in the trucking costs. How quickly can you pass those on? The customer, do they just eat 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. We try to manage the contracts with these suppliers back-to-back at the same time. There may be times during certain contracts when 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're important, so I'll ask them anyway. The first is on the pressure pumping side of the business. Clearly, there was some white space or 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. Clearly the days worked were not 40% sequentially. Can you help us understand what the utilization of is for those seven active spreads as you define them, what that utilization looked like in Q4? 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 fleets are going to be in the Northeast in Q1? It changes month to month. I would say, we definitely had a fair amount of white space in the calendar, mostly driven by the Northeast, but also a few other customer-specific issues in the fourth quarter. I look at those as relatively transitory, but it ends up looking similar in the first quarter as well because we're 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. Yeah, it does. Can you give us a breakout of where your spreads are located today, whether it be Texas versus the Northeast? 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. 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 that there's some payroll taxes that negatively impact margins that'll go away in Q2. 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 day rate that you report each quarter to be relatively flat, if not having bottomed in Q1? Yeah, let me clarify that. 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 preexisting contracts, pre-COVID and into today's market. 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. Yeah, 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 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. 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 potential consolidation there? I think in the land rig business and the way we view it is when we view the land rig business, we're looking at the super spec APEX rigs that we operate. 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. I think that we'll see leading-edge day rates move up later in the year as the rig count moves up. I'm not sure that the industry needs more consolidation the way other sectors of oilfield services need consolidation. That'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 comment there, you haven't seen it yet. Could you maybe just characterize. I guess there's sort of the push and pull of, if you increase your volume, you absorb some better fixed costs and improve your margins 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. 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. 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 it the most. As I said, in drilling, I think as the rig count moves up later in the year, there's an opportunity for the day rates 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 call. Hey, Vebs. Hey. I want to make sure I understand it correctly. You guys are saying that EBITDA for the company troughs in 1Q and then improves, but not specifically the land rig margins. Is that fair? Yeah, that's fair. As I said, I think where we are and 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 it rolls off. 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? Obviously 4Q was a pleasant surprise. We still have public guys who will add rigs. Can you talk about how much visibility you have and 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. The activity that we have today is based on plans that were put in place two and three months ago, and there's been a big shift in the commodity price. That's going to change the cash flow for our customers, but we just haven't seen that move into actual activity, and it'll be several months before we do. I'm encouraged based on where commodity prices are trading, that rig count has the potential to move up later in the year. Okay. 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 about $5 million-$6 million EBITDA per fleet in 3Q, and we decline in 1Q. At current pricing, is that $5 million-$6 million EBITDA per fleet a fair way of thinking about your profitability on average? Yeah, 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. 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. Then we have this transitory situation where activity in the Northeast is still going to be low starting off in the first quarter, maybe pick up later in the quarter, and then we're moving assets out of the Northeast into Texas. 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's 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. As commodity prices have moved up and cash flow improves, I think there's 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. Yeah, thanks. Good morning. I wanted 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. Interesting commentary about you locking in the shortest duration possible to maybe capture some upside moving forward. That makes it sound like maybe your customers aren't really willing to acquiesce to pricing, even if that meant locking in longer term. First of all, is that true? To get more term, is there a percentage pricing improvement that you kind of have locked in or you'd ideally like to see? If we stay in this gridlock, are we just presumably going to see six months 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's some upside, and I believe there is based on how commodity prices have moved over the last few months. I think that operator cash flow will improve and then activity will translate to higher rig count. I think there's upside, and so we don't want to get ourselves locked in too long. The discussion about how long we're willing to lock in a term, it's not just pure math. Certainly, we'd like a higher price if we're going to lock in a term today for a longer period, let's say a year or more. 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. It's not just about the math, in general, we're trying to keep the terms relatively short because we think we have some upside. That makes sense. Interesting commentary about the microgrids and maybe participation in renewable and smart grid build-out over time. I would imagine that's 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? 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 cruise ship was one of the larger projects we've had, and we were 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. 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. 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. 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. One more quick one if I can sneak it in. You've earmarked some upgrade capital here to dual fuel. You've 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 yourselves. Do 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? Maybe comment on relative barriers to entry for those who aren't necessarily current in terms of next-gen frac technology. Thanks. Yeah. There's 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. There's certainly no point in investing in a full frac spread right now or adding capacity to the market. I think there's 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 can make sense. Full spreads is very difficult to justify economically. Yeah. If your question was around the cost of procuring that equipment, it has come down a little, but 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? Do you have enough in inventory? When do you think you'll be in the market? I don't want to get too many suppliers excited, we're buying drill pipe. The demand is there for us. It's a great rental business. It's part of our CapEx budget. There's good paybacks on that. Yeah, we're actually adding drill pipe. Okay, good. 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? Yeah. On a per rig basis, we're still kind of in that $750,000-$1 million range per active rig. Then on a per spread basis, we're at about $4.5 million per spread in pressure pumping, inclusive of fluid ends. Okay. Fluid ends are running at what, like $1 million or so a year? Yeah, a little north of that, not much. They've come down. We're doing a better job of maintaining them in the field and getting more useful life out of them. Our fluid end usage has come down some and so has our maintenance expense. 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're sustainable. We should be at a relatively normalized type spend level per fleet this year. Okay. Andy, I know you love both of your major businesses, drilling and pumping, just thinking, in the second half, do you think, which business grows more in terms of top line from the first half levels? I think we'll see, in our case, maybe 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. Where do you want your EBITDA per crew to be before you would reactivate a crew? Right now it looks like, once you take out the cost of fluid ends, there really isn't any EBITDA per crew. Yeah. It's running pretty tight. It's still an oversupplied and challenging market today. 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. We'll just continue to evaluate it on a case-by-case basis as we look at the various projects. Does the EBITDA per crew needs to be above maintenance CapEx for you to activate a crew? Correct. Okay. At the minimum that. Okay. To get there, do 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- Yeah in the fourth quarter, and then that not increasing activity in the Northeast till later in the quarter, then there's some activity challenges there. That's going to improve the financials, when activity improves in the Northeast. With the spreads that we're working, we're above the cost it takes to work these spreads. We're certainly challenged by activity late in 2020. When it comes to reactivation, there's some costs for reactivation, and we want to make sure we cover those costs as well. Yeah. 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, that consumes more horsepower in the Delaware. Okay. Great. Thank you very much. Thanks, Andy. Thanks. Appreciate it, Waqar. Your last question comes from the line of John Daniel with Daniel Energy Partners. Hey, guys. Thank you for putting me in. Hey, John. Just one question for now. The Northeast, just your visibility into the year, do you see it recovering to the levels that the finishes at in 2020? Do you see it going higher, just your thoughts there? My discussions with operators in the Northeast lead me to believe that they're concerned about the price of natural gas in terms of overproducing up there and negatively impacting it. They're trying to keep their activity levels in check, so that they don't overproduce in the Northeast. I think a lot of what we saw in terms of Q3 going into early Q4 in activity levels was going back to wells that were in 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's relatively flat. We're not looking for a huge increase in activity in the Northeast. We do have some specific customers that will increase activity with us later in the quarter, but our rig count projection up there is relatively flat. Okay. When they come back with a little bit more activity, does that necessitate reactivating a crew, or is that filling the white space, or moving a crew back from Texas? I am just curious how you look at 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. There are no further questions at this time. All right. Well, we want to thank everybody for joining us today. 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. This concludes today's conference call. You may now disconnect.