Patterson-UTI Energy Inc
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Patterson-UTI Energy Inc
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Ladies and gentlemen, thank you for standing by, and welcome to the Patterson-UTI Energy's Third Quarter 2020 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentations, there will be a question and answer session. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions].
I would now like to hand the call over to Mike Drickamer, Vice President, Investor Relations. Please go ahead.
Thank you, Denise. 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-nine months ended September 30, 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 suggest in such forward-looking statements 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 to 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 third quarter conference call. We're pleased you can join us today.
Our financial results during the third quarter exceeded consensus estimates as our contract drilling business continues to prove its resilience in a downturn. And our pressure pumping and directional drilling businesses showed improvement in the third quarter.
Based on our customer engagement, we expect the activity will continue to improve through at least the first quarter of 2021, assuming commodity prices remain around current levels, we expect our profitability will be at or near an inflection point in the fourth quarter and higher in early 2021.
I will now turn the call over to Andy Smith, who will review the financial results for the quarter ended September 30th. I'll then comment on our operational highlights as well as our outlook before opening the call for Q&A. Andy?
Thanks, Andy. As set forth in our earnings press release issued this morning for the third quarter, we reported a net loss of $112 million, or $0.60 per share. Adjusted EBITDA was $43.3 million, which significantly exceeded capital expenditures of $13.4 million.
Our operating results combined with a further working capital base, led to a $57 million increase in our cash balance. Our cash balance at the end of the third quarter was $304 million. Activity levels have recently improved across all of our business segments.
With the increased activity levels, our drilling CapEx forecast, which was expected to be $100 million in 2020, is now expected to be $110 million. All other CapEx expectations remain the same, bringing our total CapEx expectation to $150 million for 2020. Of the $110 million of drilling CapEx, $49 million was spent in the first quarter before the downturn began.
Before I turn the call back to Andy, for the fourth quarter, we expect SG&A of approximately $22 million. We expect depreciation, depletion, amortization and impairment expense to be flat quarter-over-quarter at $157 million and an effective tax rate of approximately 13%.
Lastly, we'll be paying our quarterly cash dividend of $0.02 per share on December 17, 2020 to holders of record as of December 3, 2020.
With that, I will now turn the call back over to Andy Hendricks.
Thanks, Andy. While the second quarter for our industry saw a historic decline in activity, I am pleased to see the U.S. to become stabilized in the third quarter. And completion activity increased from the low at the end of [Technical Difficulty], for Patterson-UTI, even though our activity has declined significantly from the beginning of the year, I'm also pleased with the operational performance of each of our business segments and our continuing rollout of new technologies.
In contract drilling, our average rig count for the third quarter was 60 rigs, including 17 rigs that were idle but contracted. The proportion of rigs that were out of the contract had increased to 28% in the third quarter from 20% in the second quarter. This is dilutive to both average revenue per day and average cost per day during the third quarter as idle but contracted rigs generally received reduce dayrate, but also carried minimal associated costs.
Average rig revenue per day during the third quarter was $20,920 down from $22,970 in the second quarter. In addition to the dilution from the higher proportion of rigs receiving reduced rates, revenue per day was also impacted by less lump-sum early termination revenue during the third quarter.
Average rig cost per day during the third quarter was $10,750 down from $11,690 per day in the second quarter. In addition to the dilution from the higher proportion of rigs on standby minimal costs, operating costs benefited from a credit for sales and use tax during the quarter.
Average rig margin per day of $10,170 in the third quarter benefited from unexpected lump-sum, early termination revenue and the credit to operating cost for sales and use taxes. Excluding both of these benefits, average rig margin per day would have been approximately $9,000 which exceeded our expectations.
As September 30, 2020 we had term contracts for drilling rigs providing for approximately $305 million of future dayrate drilling revenue. Based on contracts currently in place, we expect an average of 43 rigs operating under term contracts during the fourth quarter and an average of 35 rigs operating in term contracts during the four quarters ending September 30, 2021.
Drilling activity stabilized during the third quarter and started to improve late in the quarter. Our rig count has improved to 61 rigs today from a low of 57 rigs in late August. We are optimistic about the outlook for drilling activity in the fourth quarter and expect to see an increase in activity later in the quarter. We expect to average 61 rigs for the fourth quarter, with the proportion of rigs idle but contracted in the mid-teens.
By the end of the fourth quarter, we expect to be at 63 rigs of which approximately 10% will be out of the contract. Average revenue per day in the fourth quarter is expected to decline by approximately 2% to 3% due primarily to the expected absence of the lump-sum early termination revenue in the fourth quarter.
Average cost per day in the fourth quarter is expected to be negatively impacted by having a lower proportion of idle but contracted rigs. Additionally, our expected fourth quarter rig operating cost include approximately $500 per day of rig reactivation expenses. In total, average rig margin per day is expected to be approximately $7,500 per day in the fourth quarter.
Going forward, our focus is shifting from stacking to reactivating rigs in the fourth quarter and the first quarter of 2021. We are in a great position to do so, given our broad customer base and our fleet of super-spec walking rigs, such as our advanced APEX XK that we expect to be in demand as operators return to work.
Across the U.S. contract drilling industry, we believe that while pricing will be competitive as the industry emerges from the rig count bottom, we expect the financial hurdle of rig reactivation expenses should promote pricing discipline as we move into next year.
Looking ahead, our expectation for the contract drilling industries, that pricing discipline will be similar to what we saw in 2016 and '17. As the rig count moved up from the bottom of the cycle, drilling rig dayrates also increased. And in this cycle, we expect to see more performance-based contracts which create a better-balanced economic win-win with operators.
Turning now to pressure pumping. We averaged five active spreads during the third quarter up from four active spreads in the second quarter. Pressure pumping revenue for the third quarter increased to $72 million from $59.5 million in the second quarter and pressure pumping adjusted EBITDA improved to $6.2 million.
Our active spreads were more highly utilized during the third quarter, which when combined with further improvement efficiency led to a more than 30% increase in average stages per spread in the third quarter. This efficiency improves our competitive position within the pressure pumping landscape. For the fourth quarter, we expect to average six active spreads and pressure pumping revenue is expected to improve by approximately 10% sequentially.
However, the lower utilization during the fourth quarter due to expected slowdowns around the holidays, adjusted EBITDA is expected to decrease to approximately $4 million. We're encouraged by the attrition occurring throughout the pressure pumping industry through mergers, bankruptcies and consumption, moving the industry directly and closer to a supply and demand balance.
Turning now to directional drilling, revenues were $10.3 million and the gross margin was approximately $0.5 million. We were able to increase activity and gain market share and what was essentially a flat rig market during the third quarter. Our market share increased as a result of the enhanced performance of our new technology, the Mercury measurement while drilling system and the new Mpact directional drilling motor sizes, which were introduced in the first quarter of the year.
We also continue to make great progress in the area of remote measurement while drilling operations whereby we were able to take MWD technician off the rig and perform the job from our real time PTEN+ performance center here in Houston. During the third quarter, we performed remote MWD operations on 28 wells, which equated to a 109 MWD runs and 328,000 feet of well bore footage drilled.
For the fourth quarter we expect directional drilling revenue of approximately $14 million, and we expect gross margin of approximately $1.5 million. Turning now to our other operations which includes our rental technology and E&P businesses. Revenues improved during the third quarter to $9.8 million from $8 million in the second quarter. Gross profit during the third quarter was $1.2 million. In the fourth quarter, we expect revenues and gross profits to be similar to the third quarter.
Before we open the call for questions, I'd like to give you an update on our technology and ESG progress. Technology and performance will be an increasing differentiator as we move into a recovery and we continue to move forward with remote operations capabilities for reduced costs and automation technologies for improved performance, well bore quality, and repeatability.
These improvements are enabled by the digitization of the high frequency data and metadata originating from the well site operations as well as by digitalizing our processes and workflow. These technology investments are capital-light and operate in a cloud data environment where for example, in contract drilling and directional drilling they can be added to our existing high-performance super-spec rigs, such as our popular APEX XK.
As well, we believe that we have a leadership position in the technologies that enable the use of alternative fuels for cost savings and for reducing emissions. We're seeing increased interest through more operators focus on ESG and carbon emissions in a number of our technology solutions. For example, in contract drilling, we have the largest fleet of 100% natural gas engines available in the U.S.
We are the first contractors to operate a rig with lithium battery hybrid hardware and energy management software and automated energy transfer systems that can replace a complete generator using energy storage. Our Electrical Engineering and Technology Division current power, we offer a solution and have experienced tying directly into high line utility power for an emissions free drilling operation at the well site. And our pressure pumping division Universal is one of the most experienced frac company's operating natural gas dual fuel engines.
All this combines to the Patterson-UTI Technology leadership position in the increasing importance of ESG in our industry and with an eye on the future energy transition. We can continue this capital-light and technology focused investments with a long-term perspective because at Patterson-UTI, we have a strong balance sheet, produce positive cash flow, and have highly effective operational teams.
With that, we'd like to thank the hard-working men and women who make up this company as they've worked diligently and effectively through a very challenging time both in our industry and in general. We appreciate your continuing efforts.
Denise, with that I'd like to open the call for questions.
[Operator Instructions] Your first question comes from Sean Meakim with JP Morgan. Your line is open.
Thanks. Hi. Good morning.
Good morning, Sean.
So, as we think about the first part of '21, you've indicated that we expect to see continued activity in that time that can be consistent with what we've heard. You're moving up your spread count in the fourth quarter in anticipation of that. And so, there will be a little bit of a low around the holidays. Can we just talk about confidence level in terms of being able to drive improving profitability for pressure pumping in the first quarter?
And if we look beyond that, as assuming that the frac crew count for the lower 48 moves toward the maintenance level, which is substantially higher than where it is today. And I'd love to get your thoughts around how the industry will progress from being able to currently react to a fleet at minimal cost versus requiring some form of remuneration from your customers or the frac crews that have a higher threshold to bring them back to market?
Hey, good morning, Sean. So I'll try to circle back on all that. So in pressure pumping, first off, our philosophy is if we're looking at activating a spread, we need this to be cash flow accretive to the business.
And when you look at the activations that we've made, we've been improving the margin in the business. And so the increase in activity and the other spread that will activate where we'll average up to six in the fourth quarter is not so much looking forward to 2021, because of the work that we have in the fourth quarter.
Now certainly, we'll go forward into '21 as well I believe, just because of the increasing activity in general and increasing rig count that we're seeing. But we're activating another spread going into the fourth quarter, because we believe it's going to be cash flow accreted to that business.
In terms of 2021, we have some visibility going into the fourth quarter. And we don't normally call out projections that far, but we thought because we have visibility, we would go ahead and discuss that today. I think though, in terms of pressure pumping margin, as we continue to activate spreads and it's accretive to cash flow. It also improves the margin, and we have more fixed cost coverage in that business as well, in terms of the G&A for that business.
So, I think that helps, and I'm certainly positive enough to be on how our teams at Universal pressure pumping is performing these days.
Okay, fair enough. I appreciate that context. And then, so on the drilling side, we're seeing improving activity not as a magnitude maybe as completions early on. And you indicated that you think things will be similar to the last cycle in which directionally as your activity improves, you'll see a commensurate improvement in rates.
As we think about how that flows through the model, we've got a mix of near-term idle rigs going back, and they're on the way going back to work. Eventually, we added new rigs assuming at lower dayrates and the average. There's often that point in cycle where your average rate may actually come down for a period before you retire. Just wanted to hear how you see those competing forces unfolding in the first half of next year?
Yeah, there's certainly a number of moving parts, as we come off the bottom and go into more recovery mode with our rig count increasing in the fourth quarter and then in the first quarter. As you mentioned, we got the rigs that are idle but contracted, doesn't go back to work, cost roughly neutral, as activity in our drilling business moves up, we get better fixed cost coverage. So, that's positive for the margins.
We also have all the ancillary charges that we have on the rigs as well. And so there's a number of things happening, sure. Leading edge dayrates are going to get more competitive for a period, but like we saw in '16 and '17 as we came off the bottom there, that happens for a period of time. But then as the rig count lose up, we see those dayrates move up as well.
We've said that, we're basically going to get to an inflection point in the fourth quarter and profitability moves up in the first quarter of next year, primarily driven by the drilling business because of its relative size within our organization.
Got it, great. Thanks Andy.
Your next question comes from the Chris Voie with Wells Fargo. Your line is open.
Thanks, good morning.
Good morning.
So on rigs, I guess I wonder if you can comment on the nature of dayrate discussions. Currently, it sounds like you have visibility for an increase in the fourth quarter and the first quarter. Are we still talking mostly direct negotiations or there are any competitively bid kind of rigs coming to market at this point?
So, just to clarify, we have visibility to activities moving up in the fourth quarter and the first quarter. I think that, because we are at essentially at bottom in U.S. rig count activity as an industry, there's still going to be some competitive pricing out there.
But with the activity improvements we're seeing, that's why we see an inflection in the profitability in the fourth quarter and moving up in the first quarter. But there will be some competitive dayrates out there that are bid. But remember, we also have our ancillary services that we provide on top of those dayrates. So we see that as a positive.
Sure. And then when I think about the last cycle and the tailwind for rates, I think the upgrade piece of that was a pretty big driver, a need to create more super-spec rigs. Just curious, is there any more of that on the horizon for you guys as more rigs go back to work and other new technologies that anything along the lines of ESG or other stuff that operators are going to want to put onto rigs that might be a tailwind for rates going forward?
I certainly don't see it as a tailwind for - well, it's certainly positive for rates, let me clarify that. Anything that customers want us to do in the area of ESG and technology is positive for those dayrates, whether it's adding a 100% percent natural gas engine or it's adding our EcoCell lithium battery hybrid energy storage solution, that's positive for the dayrates.
And I think we'll have to wait and see how much interest it moves into '21. But there's certainly interest today and we're in those types of discussions and we're operating some of that equipment today. I think that, the ancillary equipment that we provide, not just the new technology, but, the ancillary equipment that we've been providing for years has still been very supportive. And that's why for the fourth quarter, we're seeing average revenue per day still above $20,000.
Great. Thank you.
Your next question comes from Taylor Zurcher with Tudor Pickering. Your line is open.
Hey, thanks and good morning. First question is on some of this or the wave of upstream consolidation we've seen over the past few months. On the one hand, it's creating fewer customers for you, which is not going to be a good thing. On the other hand, you've got a larger well capital-light or better capital-light players that probably are more interested in the higher technology and efficiency improvement of the service offering that you have.
And so, as you point that all together, I'm just curious how you think this wave of upstream consolidation is going to impact your business over the next 12 to 24 months?
Well, we're very fortunate at Patterson-UTI, our teams have done a great job where we have a very broad customer base, from the largest oil and gas companies you buy gasoline from at the corner down to private companies that you may have never heard of. And this broad customer base has always been a positive for us. It was a positive in the downturn until rig count stabilized in the third quarter and it's going to be a positive for us in the recovery.
Sure, some consolidation creates some near-term challenges, but we still have a very large number of customers that we work for. And I think, while that does create some near-term challenges with consolidation, it probably creates some long-term stability in the market as well. So, I think it's neutral for us to have the consolidation that we're seeing when I look at our customer base. So I don't see a big concern there for us.
Okay, thanks. And my follow up is on free cash flow. Over the past really several quarters, you've been generating some pretty healthy free cash flow around the cash balance. And a lot of that's been chewing through some legacy contract drilling backlog and working capital benefits. Moving forward, both of those benefits are likely to turn the other way.
And so, I was hoping you could help us think about free cash flow expectations over the next six to 12 months. And what do you think you can stay positive from a free cash flow perspective in that time frame?
Yes, I mean, look, near-term, I certainly think that our results should outperform our CapEx. On the working capital side as activity turns up, we will invest a little bit more in working capital. But I don't suspect that it will be enough to overwhelm sort of the spread between what are our sort of operating results in our CapEx. So I would expect to remain free cash flow positive.
Got it, thanks guys.
Your next question comes from Scott Gruber of Citigroup. Your line is open.
Yes, good morning.
Good morning.
I want to come back to the rate inflation comments. During the upcoming cycle, Andy you touched on the technology and ancillary service benefits, but do you think that quality companies such as Patterson will also need to be more demanding in terms of pushing for improved pricing at a certain point in the recovery?
I know we're not there today, but at certain point you do think you need to be more demanding. Do you think - what do you think that pricing power could swing back to your way without demanding price increases? I'm just wondering whether you really need to show willingness that you're willing to lose share, obviously the first request for any type of price increasing invariably be denied.
But do you think that you and other quality peers just at certain point sit back and say, we're just not going to work for these rates any longer and show their willingness to lose share?
So, I think it's interesting because we have never been a company that focuses on market share. We've always focused on the margin. And doing so, that we ended up gaining share in the downturn in all product lines, but we're always focused on the margin.
So yeah, there will be times during 2021 that we actually lose out because we are pushing pricing and our teams are always doing the best, they can to push pricing to where it makes sense. And so, I think that we're going to keep that same focus to stay focused on the margins.
Just wondering whether there's a point where we try put a little more emphasis on the pricing side, and say, hey, we need more, we can go to work, put a fleet back to work at a positive cash margin here, but it's just not giving us the returns that we're really looking for on a long term basis. So is there an inflection point where do you get to a certain rig count and just say, enough is enough, we need a step up in pricing to move beyond this level, and what that level could be?
It'll happen in 2021, I think similar to how it happened in 2016 and '17. When we're coming off the bottom, there's always that competitive nature, everybody wants to get their rigs back to work. But once you start putting rigs out, then discussion starts to change. And I think pricing will move up in 2021.
Got you. And then just in terms of the cadence of recovery, I guess one, do you think there's going to be an inflection in the cadence upon a budget refresh in 1Q? And secondly, I think the current floor which strip for oil and gas, but when do you think we can adapt to these maintenance levels of activity that possible in the first half of '21 or is it more second half or two uncertainty there?
It appears that the first half of '21 and the activity increases that we're seeing are really about a mixture of different philosophies at different customers. We've got some customers, we just need to go back and drill some wells and maintain some production. We got some customers that feel like they're profitably economic at this point on some of their fields and some of the pads that we're going to go back and drill. So it's two different mindsets.
So I think that drives the first half of 2021. I think that the second half of '21, it's really going to be more about the macro, what our global economy is doing, where we finally starting to open up and move past all this mess that we've all been dealing with. And I'm hopeful there. I think we're all tired of it. But I'm hopeful that as we get into the second half of '21, the economies are more open, and that's going to drive energy demand.
We're all hoping. Thanks for the color Andy, I appreciate it.
Thanks.
Your next question comes from Kurt Hallead with RBC. Your line is open.
Hey, good morning.
Good morning, Kurt.
So Andy, you made a reference earlier on about increased performance related and fee-based drilling, contracting, and revenue streams, and so on and so forth. So just wondered if you can give us an update on that, I think you've referenced some percentage, I think in the last quarter and I want to see how that was progressing here in the third quarter, then maybe how you see that evolving as you get into 2021?
So this quarter, we have about the same percentage of non-traditional dayrate contracts as we had last quarter, which is about 30%. I think that will be similar in the fourth quarter. It'll be more in the 2021 as rig count improves a little bit more that I think we'll have that kind of opportunity.
I think that, in the discussions we're having with customers today, they're intently focused on the dayrates and trying to get the best deal they can. And I think that'll shift in 2021 as more rigs go back to work. And I see that we're going to have more opportunity to have more of these non-traditional dayrate contracts, which I think are more of a win-win, not just for us, but drilling contractors in general. And so I can see that happening as we get further in 2021.
Okay. That's great. And you made a reference both in your prepared commentary and in the press release about the lithium battery powered and energy storage dynamic. I think that is related to drilling rigs right. So what there has always been a fairly slow evolution for the industry to adopt new ways of doing things, right? And it's a wonderful, almost 10-year period for the EP industry to fully embrace the agency rig dynamic and make that a very good choice for virtually every, every player.
So, I don't know, could you put this lithium battery power dynamic into context for us and historic context for us and give us some sense of how quickly maybe this go around if there's going to be an acceleration in that adoption and when that acceleration might start to occur?
So, some of these changes don't happen very fast at the bottom of these cycles. But since we have visibility that we're coming off the bottom, I think we're going to see some nice uptake in a number of these technologies.
The EcoCell lithium battery hybrid storage system that we have, it also comes with energy transfer automation system that moves the energy between the engines and the lithium battery storage system. And this can be put on any of our APEX rigs. And the good news is, this is all relatively capital-light investments competitor to the investments that we've made in past years.
And so, those technologies as well as others which are even lighter on the capital side are exciting for us, because we can improve the performance of the operation, and we can save an operator money on costs. We can reduce emissions in a number of these technology cases. And I think these are all the pluses for us. It makes us very competitive out there. And it allows us to push rates in places as well.
And thanks Andy for that. As a follow-up, are you saying that the oil and gas operators are now starting to require lower emission standards from their fraced and drilling contractors?
I think it depends on the operator, I think you see some operators moving in that direction. I think that wave will continue. But I think it's still very early days. And so there's still upside there for years.
Okay, thank you.
Your next question comes from Jacob Lundberg with Credit Suisse. Your line is open.
Hey, good morning, guys. Thanks for taking the question. I wanted to start off by just kind of following up on the performance-based contracts. Could you remind us how you structure your performance-based contracts first? And then secondly, any color in terms of how daily margin on those contracts looks relative to traditional would be helpful?
Yes, in terms of structure, what I've said before is we do various things. And it really depends on the operator and what their focus is. In some cases, these are indexed to commodity, in some cases, they might be about footage per day, how many wells per month, in that kind of term.
In other cases, it might be tied to reduce downtime, reduce non-productive time at the well site. So, it really depends on the focus of the operator and what they're trying to accomplish and what they're trying to improve. And I certainly wouldn't want to get into a discussion about what it can do for our margins, but we wouldn't do it if it wasn't accreted to margins.
Okay, fair enough. I guess, second unrelated question. I'm curious what you're seeing in terms of appetite to add rigs, kind of bucketed by customer type. So, is there a particular type of customer we're seeing more or less willingness or aggressiveness and in their plans to kind of add rigs over the next couple months?
Well, I think this is similar to previous downturns, where your largest E&P companies out there have, very, I'll say large budgeting processes to go with their size. And so they take some time to make some decisions and react. And it's going to be your more nimble private companies, and you're more nimble publicly mid-tier companies that are going to move quicker off the bottom.
And I think that's what we're going to see. And I think you'll see that in the rig count data as things become more public. But overtime, we'll start to see the larger companies kick into gear as well. So, we were fortunate in the broad base of customers that we have today. And like I said before, hats off to our marketing and operations team to put that customer base in place and all of our businesses.
Alright, thanks a lot. I'll turn it back. Thanks.
Your next question comes from Blake Gendron with Wolfe Research. Your line is open.
Yes, thanks. Good morning. So my question is kind of along the same lines with a lot of other questions that have been asked, but the exercises last cycle or maybe last several cycles was tight. This is what a Tier 1 rig is. This is what demand is and so we kind of back into the utilization.
If we were to appreciate the fact that Tier 1 and those goalposts have shifted even from cycle to cycle and now, you're starting to layer on these digital and ESG type considerations. I know that these are capital-light add-ons, but I would imagine you've been doing this a long time on not all these digital and ESG offerings are really the same.
If you were to designate sort of a call it smart rig contingent, have you tried to itemize or tried to figure out how many of these rigs are actually in the market being marketed today, just so we could maybe try to back into a utilization level needed to start seeing some bifurcation in pricing?
Yeah, I think it's still early. I think it's probably difficult to get visibility on especially across the industry what's out there and what's happening. I will say this, I think that the rig discussions today begin with the structure of the rig. And you guys know, I keep calling out the APEX XK, we also have our XE and PK.
But it really starts with a discussion on what the rig structure looks like when let's declare it under the floor. Can we get back on the pads that we were on previously? Can we walk over and across various wellhead and production equipment on a pad? And what's the flexibility there?
And that's why our APEX XK has been so popular in the market, because we have a drawer test design, a lot of clearance underneath, and we can move around the pad. And that's really the base of where all these discussions start. And after that you start to get into what can you do to reduce fuel costs, what can you do to improve emissions and help the operator on their ESG score?
And then, what does a remote operation do to reduce costs? And what does automation do to improve performance efficiency and repeatability and drill better quality wellbores? And so, every operator has a different tag on what's important for them right now. And so, it's hard to itemize our bucket technologies for those various reasons. And you're going to see rigs that are out there working with various levels of technology depending on the operator.
So just following on that answer there, with the emergence of simul frac hub and nascent crew sizes are getting bigger on the frac side. Are the wellheads and the production stacks, are they getting bigger as well where clearance becomes an even bigger issue here in the coming quarters and years?
I think clearance is a bigger issue this year, because you've left pads and you want to get back on you've done things on those pads, you've gone back and fraced wells, maybe you haven't completed all the drilling on those wells and so now you got to get back around wellheads and trees and production equipment.
And so that's why I think a lot of these discussions really start with, let's talk about the clearance and how you can walk around these various systems on a pad and have that mobility in place. And then it's then the discussion is around later on technology.
Understood. One more quick follow up if I can, just on the directional drilling side, we've seen rotary steerable has become a more in vogue technology. But in the lower 48, it seems like motors are becoming increasingly capable to do the same things. You have a bundled solution some of your drilling peers have a bundled solution.
How can the third-party directional drilling companies really compete in this lower activity environment? And what are you seeing competitively that would suggest that they will hang around or that we could see some attrition on that side of the market?
Well, I think the most compelling data right now is that we've been gaining share, and we've been gaining share in a flat rig environment. The new technology is proven to be very reliable. And when other companies are having challenges and we get a phone call, we replace them and we keep that rig and we keep that operation.
And so, that team has been performing great. And I'm still very optimistic about their growth potential even though our drilling activities moving up in the fourth quarter and the first quarter, I think our directional drilling business can grow at a faster rate than the rig count. Again, that's still a capital-light business.
So I think, what we're doing there in terms of performance on the technology we introduced this year combined with the technologies of remote operations and automation that will tie directional closer to the rig, I think it will be tougher for smaller directional companies to compete the U.S. market.
Got it. Thanks.
Your next question comes from Jill Merchant [ph] with [indiscernible] Columbus. Your line is open.
Thanks for accepting my question. Just was wondering with the bonds trading at a somewhat stress level, if you are contemplating using some of your cash to do some balance sheet optimization?
Yeah, hi Joe. Obviously earlier in the year, with the sort of severe downturn we sort of made a concerted effort to focus on liquidity throughout the year and look as the outlook is brightened and we've got a little bit more visibility, we've entered into a sort of a time where we look at our liquidity and say, okay, maybe we've got plenty.
I don't want to set any expectations on this call, but know that we're thinking about a number of different things. But just not ready to sort of probably set an expectation for what we'll do.
Thanks. That's fair. And then one stupid question I just picked at the release and the debt seemed like it was at the same level as last year, but your interest expense, it seemed like was cut in half. What's behind that or am I reading that wrong?
Again, [Indiscernible] we probably got some early retirement vehicles in our interest expense last year.
Thank you.
[Operator Instructions] Your next question comes from Chris Voie with Wells Fargo. Your line is open.
Thanks for letting me back in. Just to expand on earlier line of thought, there's been discussion of pricing moving up, but not really from what level. I don't know, if you can comment on where you think these big rigs will be? Is that going to be like, mid-single digit 1000 per day? And if not, maybe if we could get some color on the 43 rigs that are on term in the fourth quarter versus a 7500 margin per day. Like how many of those rigs predate 2Q '20 if there's some kind of pieces you can give us there?
Yeah. The dayrates will be competitive at the leading edge as we come off the bottom just like they have in the past cycles. I don't want to go and really discuss what levels I think those are at, because they are competitive and we want to stay competitive. We also want to try to push pricing where we can't do.
But remember, it's - we also have all those ancillary services as well, which really boost the revenue per day. And that's why I said, I expect her average revenue per day in the fourth quarter to still be over $20,000 per day. I don't have in front of me those the numbers that would help you understand what those rigs would look like on the contracts. But sorry I can't help you there.
Yeah, that's fair. And then just one, is a bit of kind of like a crystal ball kind of question, but you have visibility for activity going up. I wonder if you have any thoughts on the kind of range that the rig count for you guys might be at exiting the first quarter. I understand that it's guesswork, but do you think it could be 10% 20% growth or anyway to bucket what the opportunity is?
I think right now, it's too early for us to call what the overall first quarter looks like outside of just the visibility we have their rig counts going up and that happens for us earlier in the first quarter. So I really can't speak to what happens later in the first quarter here.
Okay, fair enough. Thank you.
Appreciate it.
There are no further questions queued up at this time. I'm going to call back over to Mr. Hendricks for closing remark.
Well, I'd like to thank everybody for joining in today. Denise, thanks for managing our call. And on behalf of Patterson-UTI Energy and all the people that are working hard every day to do the great things they do, we appreciate your time. Thanks.
This concludes today's conference call. You may now disconnect.