Patterson-UTI Energy, Inc. (PTEN) Q1 2020 Earnings Report, Transcript and Summary

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

Thank you, Suzanne. 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 months year-ended March 31, 2020. Participating in today’s call will be Mark Siegel, Chairman; Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer. A quick reminder that statements made in this conference call that state the company’s or management’s plans, intentions, beliefs, expectations or predictions for the future are forward-looking statements within the meaning of the US Private Securities Litigation Reform Act of 1995, the Securities Act of 1933 and the Securities Exchange Act of 1934. These forward-looking statements are subject to risks and uncertainties as disclosed in the company’s Annual Report on Form 10-K and other filings with the SEC. These risks and uncertainties could cause the company’s actual results to differ materially from those suggested in such forward-looking statements or what the company expects. The company undertakes no obligation to publicly update or revise any forward-looking statements. The company’s SEC filings may be obtained by contacting the company or the SEC and are available through the company’s website and through the SEC’s EDGAR system. Statements made in this conference call include non-GAAP financial measures. The required reconciliations to GAAP financial measures are included on our website, www.patenergy.com, and in the company’s press release issued prior to this conference call. And now, it’s my pleasure to turn the call over to Mark Siegel for some opening remarks. Mark?

Thanks, Mike. Good morning, and welcome to Patterson-UTI's conference call for the first quarter of 2020. We are pleased that you could join us today. This morning, I will turn the call over to Andy Smith, who will review the financial results for the quarter ended March 31st. He will then turn the call over to Andy Hendricks, who will share some comments on our operational highlights as well as our outlook. After Andy's comments, I will provide some closing remarks before turning the call over to questions. Andy?

Thanks, Mark. As set forth in our earnings press release issued this morning, for the first quarter, we reported a net loss of $435 million or $2.28 per share, which included pre-tax, non-cash impairment charges totaling $406 million. These charges include a $395 million impairment charge for the remaining goodwill on the company's balance sheet and a $10.6 million impairment charge related to certain of the company's E&P – while our operating results were better than expected, market conditions changed quickly late in the first quarter, and we have taken decisive action to protect our strong financial position. First, our cost structure is highly variable and direct field level costs will decrease as our drilling and completion activity slows. Additionally, we have taken steps to structurally reduce our indirect support costs at both the regional support level and central SG&A by what we estimate will be approximately $100 million annually. These steps are expected to result in accounting charges during the second quarter, totaling approximately $50 million, though most of the cash outlay associated with the charge is expected to extend in 2021 and beyond. This $50 million of charges is expected to be recouped within approximately six months through cost savings. Second, as previously announced, we reduced our planned capital expenditures for 2020 by $110 million to $140 million. The $140 million of capital expenditures includes approximately $100 million for contract drilling, $20 million for pressure pumping and $20 million for directional drilling, other operations and general corporate spending. Note that we spent approximately $72 million in the first quarter, so remaining cash to be spent this year is just under $70 million and is primarily related to Capex. Third, we halted our share buybacks in the first quarter after repurchasing $20 million of stock. We do not plan for additional share buybacks at this time. Additionally, the Board of Directors has made the decision to reduce our regular quarterly dividend by 50% to $0.02 per share. The decision to reduce the dividend reflects a balance between managing our liquidity and continuing a cash distribution to our shareholders. Our focus throughout the remainder of 2020 will be on further cost reductions and cash preservation as we weather this period of significant uncertainty and volatility. We ended the first quarter with $752 million of total liquidity, including $152 million of cash and $600 million available under our undrawn line of credit. We had $975 million of total debt outstanding at March 31, of which our $100 million term loan matures in 2022, and the remaining $875 million matures in 2028 and 2029. With a strong balance sheet and ample liquidity, Patterson-UTI is well positioned to weather the current downturn in the industry. Before I turn the call over to Andy, for the second quarter, we expect SG&A of approximately $26 million, down from $30 million in the first quarter. We expect depreciation, depletion, amortization and impairment expense of approximately $166 million and an effective tax rate of approximately 20%. With that, I'll now turn the call over to Andy Hendricks.

Thanks, Andy. First, I hope everyone is staying safe and healthy. Before going into the individual business segments, I would like to take a moment and give everybody an update on our response to the coronavirus as well as general market conditions. Much of the energy sector has been deemed a critical infrastructure sector by the U.S. government, and our employees are considered essential workers. The states in which we work have followed this federal guidance, which has enabled us to continue operations and has enabled our employees to continue working despite various state issued quarantine or stay-at-home orders. We continue to follow guidance issued by the CDC and other federal, state and local government agencies related to, among other things, social distancing, including remote work arrangements where possible, personal hygiene and cleaning and disinfecting work environments. We have a risk mitigation plan in the event of exposure or potential exposure, and we communicate regularly with our employees and customers regarding our efforts to maintain a safe work environment. Today, we have not had any disruptions to our operations directly related to COVID-19. I would like to express my appreciation to our employees for doing their part and facing these challenges by continuing to perform their jobs as safely as possible so that the company can continue to meet the needs of our customers. Thank you for adhering to the additional guidelines regarding hygiene and social distancing. By doing so, you have helped us to protect the safety and welfare of all of our employees and those with whom we work, while continuing to provide high-quality service to our customers. Thanks, again. We will continue to take action to manage through this downturn as needed, and our goal remains that we emerge from these difficult times as a stronger company. As part of our dedication to our community and responding to the national need, we have begun manufacturing hand sanitizer and donating it to health care facilities. Additionally, we are donating excess on hand personal protective equipment, or PPE, to hospitals and first responders. Turning now to market conditions. In response to the rapid decline in oil prices, E& P companies acted swiftly to reduce activity late in the first quarter, pressure pumping activity reacted much sooner, but we are now seeing a severe drop in our rig accounts. While the circumstances, leading to this downturn in activity maybe different than prior downturns our response will be will be guided by the same principles that have guided us through prior downturns. Our team knows the playbook well and unfortunately in this environment, we must scale down the company as quickly as possible to align with lower levels of drilling and completion activity. While simple in concept, the key is in executing this plan, effectively and efficiently, and at the same time dealing with our current travel and social distancing restrictions. While this will be a difficult down cycle, we will continue to move our technologies forward. We have made great progress over the years in the areas of digitalization through data analytics, control systems, machine learning and our steps forward in remote operations and automation. Our PTEN+ data system is world-class in its ability to measure performance in drilling operations and is the backbone for the data required by our other systems. Our Cortex automation apps tied to our control systems continue to improve drilling performance at the well site, and the uptake was growing in the first quarter. We are actively conducting remote directional MWD activities, reducing the required employees on the rig and have the capability to also perform remote directional drilling operations. As the only contract driller with a large U.S. directional drilling operation, we are uniquely positioned to advance the automation of directional drilling with scale in onshore operations In 2020, we will also introduce remote blender operations in pressure pumping to reduce costs and improve performance. Patterson-UTI is positioned well to not only embrace the digitalization of the oil field, but also to be a leader in to generate incremental revenues and returns from this move to digitalization. Turning now to the first quarter. In contract drilling, our average rig count was 123 rigs, unchanged from the fourth quarter and in line with our expectation. Profitability and contract drilling exceeded our expectation as both revenues and direct operating costs were better than expected. Average rig cost per operating day of $14,550 decreased $990 sequentially and was lower-than-expected due primarily to lower expenses for rig repairs and maintenance. Average rig revenue per operating day was $23,800 and the average rig margin per operating day increased to $9,250. As of March 31, 2020, we had term contracts for drilling rigs providing for approximately $440 million of future day rate drilling revenue. Based on contracts currently in place, we expect an average of 71 rigs operating under term contracts during the second quarter and an average of 50 rigs operating under term contracts during the four quarters ending March 31, 2021. Turning to the second quarter. We expect that our rig count, including rigs on standby will decrease by approximately one-third from the first quarter average. We expect more rigs will be put on standby by the end of the second quarter. These standby rigs are under term contracts, but are not currently being utilized by the operator, but still generate revenue. The operators pay a reduced standby rate, which is dilutive to our overall average rig revenue per day, but standby rigs have minimal costs, thereby, also reducing our average rig operating cost per day such that the impact to our margin per day is limited. Including approximately $8 million of revenue from lump sum, early contract terminations, we expect our average rig margin per day during the second quarter to decrease by less than 5% from the first quarter. Turning now to pressure pumping. We averaged 10 active spreads during the first quarter, in line with our expectation. Pressure pumping revenue for the first quarter was $125 million with a margin of $10.3 million, which exceeded our expectation. I fully acknowledge that this business has recently underperformed, however, we've been in pressure pumping since 1980, with frac, cementing and acid stimulation, and we have a long history of success. We have taken a number of steps, which I believe will make us more competitive. Over the first half of 2019, we made progress in improving our adjusted EBITDA per spread despite activity declining. However, with continued declines in activity in the second half of 2019, our results were negatively impacted by the slower activity and lower fixed cost absorption. During this period, we continue to evaluate and reduce our cost structure, but we're behind the pace of the activity slowdown. Prior to the recent slowdown at the end of the first quarter, we started implementing major structural changes to further reduce our cost structure while maintaining our excellent service levels. Our team has scaled the business quickly to create a much flatter and more efficient organizational structure to support what we believe is the activity level going forward in 2020. We believe that this new structure will reduce indirect support costs in the pressure pumping segment by approximately $65 million on an annual basis. For example, we have closed our facility in the Mid-Con region and consolidated our operations to two primary regions, the south and the northeast. Within the south, we have consolidated maintenance to one facility in Midland and closed three other maintenance facilities. In the northeast, we are closing two of our traditional support facilities. Along with this, we have centralized certain support functions between the regions in order to reduce redundancies, and we have eliminated an entire level of management. We've also worked with our vendors to reduce costs. The downturn in completions activity began quickly in March as this was a fast way for our customers to preserve capital, and we ended the first quarter with five active spreads. Based on current conversations with customers, we expect to average approximately four active spreads in the second quarter. Excluding potential restructuring charges in the second quarter, we expect our pressure pumping segment to be adjusted EBITDA positive despite revenues declining sequentially by more than 50%. I'm proud of what the pressure pumping management team has been able to execute over the last few months. While there is still uncertainty in this market following restructuring costs in the second quarter, on a go-forward basis, we intend for our pressure pumping business to be adjusted EBITDA positive and cash flow positive in the back half of this year. We have scaled our pressure pumping business for a four spread operation in 2020 while still preserving growth potential for a future improved market. Turning now to directional drilling. Our directional drilling financial results were in line with our expectations with directional drilling revenues of $34.5 million and a gross margin of $2.2 million. The gross margin as a percent of revenues decreased to 6.3% as we front-loaded some development costs in the first quarter in order to bring new technology to market. In the first quarter, our directional drilling team introduced two new technologies, the Mercury Mpower measurements while drilling tool for enhanced durability in tough environments and lower operating costs, and the new impact drilling motor for improved directional control and higher drilling performance. We were pleased with the customer uptake before the market changed and will be in a strong technical position when the market eventually improves. Going forward, the new technology development costs will subside, and we are centralizing repair and maintenance activities and other support infrastructure, which we estimate will save $10 million of annual support costs. For the second quarter, we expect directional drilling revenues of approximately $15 million with a gross margin of approximately breakeven. We expect to spend approximately $3 million of CapEx in our directional drilling business this year, of which $2 million was spent in the first quarter, and so CapEx going forward in this business will be limited. Turning now to our other operations, which includes our rental, technology and E&P businesses. Revenues in the first quarter were $19 million with a gross margin of $2.9 million. For the second quarter, we expect revenues from our other operations segment to decrease by 40%, margin as a percentage of revenues of less than 10%. Before I turn the call back to Mark for his usual concluding remarks, I would like to say a few words as this will be Mark's last earnings call with us. First, I would like to thank Mark for his incredible commitment and energy to both Patterson-UTI and to the industry over the last 25 years. Through his visionary leadership, acquisitions and organic growth, UTI Energy grew from a small regional drilling and pumping company to combine with Patterson Energy and become a leading oilfield services company and a primary player in the U.S. unconventional shale revolution. Mark has been a great mentor to me. He's also been a great friend, and I wish him all the best as he takes more time with his family. With that, I'll hand it over to Mark.

Andy, thanks, and I really mean it. Thank you. Thank you. As the saying goes, this isn't our first rodeo. We have been in this business a long time, and I personally have been through many more of these downturns than I would like to admit. While these downturns present near-term challenges, they also present long-term opportunities. We have historically seized upon these opportunities to strengthen and grow our company and I am confident that Patterson-UTI will emerge from this downturn even stronger, even more technologically advanced and even more competitive. As you may be aware, this marks my 25th year with the company. It's been quite a run. I have truly enjoyed being an important part of what we've built here at Patterson-UTI, and I'm extremely proud of our many accomplishments. Over the past year, I wrestled with the decision to retire as Executive Chairman, as I have such affection for and pride in the company and its management team. And of course, I was hoping to do so during a cyclical high. Ultimately, I decided that the supremely talented management team in place will continue to manage the company in a superb manner. And after 25 years, it's simply time for me to let others take charge. In the words of one of my favorite football players of all time, when asked about his retirement, he reportedly said, it's better to retire one year early than one year late. And, of course, my retirement has nothing to do with oil prices or the COVID-19 outbreak; it's simply my own sense of a term limit. While I'm stepping down as Executive Chairman and from the Board of Directors as of the annual meeting, I'm pleased to not be disappearing completely. I am humbled that the Board has asked me to provide transition support services and assistance as Andy and the Board may desire. And that serves as a way for me to put my many years of experience with Patterson-UTI and in the oil industry to good use. Before we open the call to questions, I would like to say thank you to all of the healthcare workers on the front lines of the COVID-19 pandemic, the doctors, nurses, associated support staff and EMTs. Also a huge thank you to all of the essential employees keeping things like grocery stores and pharmacies open and operating. And thank you to all the hard-working men and women who make up Patterson-UTI. Operator, we'd like now to open the call to questions.

Thank you. [Operator Instructions] And your first question comes from the line of Sean Meakim of JPMorgan. Your line is open.

Hi. Thanks. And Mark, best of luck.

Thank you.

So just to start, Andy, I really appreciate the guidance for 2Q in pressure pumping. Just considering where the completions market is headed, the speed of the decline in demand, it seems constructive you're able to stay EBITDA positive in the quarter. That said, it also means you're negative on a cash margin basis after maintenance for the second quarter. So if you look beyond 2Q, where there's so much acute pressure on the producers, do you think you'll be able to avoid consuming cash with the business in the coming quarters? And if not, what are the levers do you have available to you?

Yes, Sean. So what's happening is, we scale down the activity quickly, which started at the end of the first quarter and still coming down in the second quarter. We have a lot of costs that move into the second quarter that don't come out in the second quarter. But as we move past that and we get into third and fourth quarters, second half of the year, it's my full expectation based on the size of the business that we're going to have, the size of the organization, the size of the support organization, et cetera, that we're adjusted EBITDA positive and cash flow positive on an ongoing basis after the second quarter.

Got it. I appreciate that. That's very helpful. And I think -- so looking at the broader business, activity is coming off in the drilling business as well, but much more helpful margins as a starting point. As you look towards the back half of the year, what's your confidence level in terms of being able to generate free cash? And does the front-loaded CapEx give you a lot of that comfort, or anything else with respect to working capital that you'd highlight? It would be great to walk through some of those pieces around cash, particularly those that are a little more within your control.

Yeah. Overall, I expect that Patterson-UTI is generating free cash flow. Looking at the term contract backlog that we have, looking at the projections that we have internally for the rest of the year. No question in my mind based on what we can see today that we're positive free cash flow for the company. We've made the adjustment to the dividend. We think it's prudent. We didn't necessarily have to, because we have cash available, but we just thought it was prudent based on the current overall global economic conditions.

Yes. Hey, Sean, this is Andy Smith. I would also add that Andy's comments don't include a huge amount of working capital harvesting. Kind of looking forward, I would expect -- we didn't end the quarter with a huge amount of working capital. I think we had $78 million of working capital at the end of the quarter ex cash. And I would kind of guess that we'll probably harvest maybe $20 million of that between now and the end of the year.

Got it. Okay. Thank you for that feedback.

And our next question comes from the line of Chase Mulvehill of Bank of America. Your line is open.

Hey, good morning. Mark, I wish you well. I'm sure that you will stay in touch with the oil and gas market, but wish you well in your official retirement.

Thank you.

I guess, first, thinking about 2Q and I know that it's a little bit cloudy and murky when we think about 2Q. But when we think about rig activity, a couple of questions, I guess number one is, where do you think the rig count bottoms for you when we get to -- when all this shakes out? And then what's the exit rig count when we think about 2Q and your implied guide?

I think the best way to describe it is the rig count is coming down fairly quickly still along the same pace. We'll probably exit the second quarter somewhere just above 70 rigs. That's probably the best visibility we have right now or close to 70. I think, overall, this is going to be a very rapid downturn. Our overall activity and I think it's activity in the industry, not just us, is going to come down 60% or more potentially. But that's -- that visibility through the end of the year is still a bit cloudy, I would say. But we have some visibility of what's happening over the next quarter and into the third quarter, but the rig count is still coming down fairly quick. We have a lot of our customers that are slowing their activity quickly and many of them have already made announcements in that regard.

Okay. And thinking about 2Q in your -- I think you said 71 term rigs. And then your implied guide is about 82 or so overall rigs active during the quarter. That implies some spot rigs. So is that really the right math? And are companies actually really running some spot rigs? And if so, what kind of day rates do you see?

No, I would expect everything that we have working going forward is -- are rigs that are under term contract. I wouldn't expect to see anything in the spot market. One of the ways that the E&Ps are looking at how they decide which rigs to let go are really kind of based on the term contract structure that they have for the rigs that they're operating. So they're going to run their spreadsheets and decide how quickly or what are the lower cost opportunities for them to exit rigs. And of course, spot is what goes away the quickest. So I would expect that what we have working going forward or all the rigs under term contract.

Okay. Got more questions, but I will turn it back over. Thanks Andy.

Thanks.

And your next question comes from the line of Kurt Hallead of RBC. Your line is open.

Hey good morning and one of the first to wish Mark today enjoining in your retirement. I think you've been a great financial steward over period of time as Chairman and congratulations on that. And secondarily, hope that everybody and their families are healthy from the Patterson group.

Thank you for both of those thoughts. Happy to report the answer to the second question is yes.

Good for you. I appreciate the color commentary on the outlook. And those things are kind of really kind of murky. So I – maybe attack the since Chase hit the land drilling question, ask you a question on the frac side of the business. So it looks like you're going to be running about 4 frac rate into the second quarter. And do you think at this stage, Andy, that that kind of stabilizes at 4, or you think it's possible that that 4 could even go lower during the second half of the year?

I think that for now, our visibility is that we stabilize at that number 4 frac spreads in Q2 and past Q2, at the very end of the year we don't have a lot of visibility. That's going to be a ways off. But I would say that we stabilized around that number of 4 frac spreads. And hence, that's why we've restructured the entire organization and the supporting structures around that number.

Just a quick follow-up. Thanks for that. In the context then is the dynamic at play in the frac market is there incremental pricing pressures, or again, is pricing at a level that's so low that it's really going to wind up, stabilize it?

Yes. I think that pricing was already pretty low after the oilfield services activity in 2019 dropped by about 1/3, pricing was already under pressure. We don't see any significant pricing pressure at this point. It's more about discussions of either you need a frac spread or you don't need a frac spread.

Okay. Got it. And maybe one for Andy Smith. Your next nearest maturity is in 2022 at $100 million. What's the game plan? Is there any thought of potentially paying that debt down earlier than 2022?

Yes. I would say in today's environment, we don't see any need to take it down earlier. Look, we've got, again, a lot of cash on the balance sheet and a completely undrawn $600 million revolver, so -- which doesn't expire until 2025. So there's no point in getting ahead of it, in my mind in today's type of environment.

Got it. Thanks for that. Thank you.

And our next question comes from Scott Gruber of Citigroup. Your line is open.

Good morning. And also wish Mark a very happy retirement. It's been a pleasure watching you help shape Patterson over the years and interacting with you. So best of luck and enjoy.

Thanks for those comments.

Andy, how should we think about the evolution of your daily drilling costs over the next several quarters and you have increased stacking costs here in 2Q, but those fade, but then in the second half of the year, you'll have less of the support costs being absorbed across fewer operating rigs. How should we think about the daily drilling expense over the next several quarters?

Yes, there's going to be a number of moving parts in that number as we proceed through the year. So, you've got the rig count coming down. We're adjusting the costs around that and then we can only adjust so far and then as the rig count gets lower later in the year, there'll be less fixed cost absorption. We also have rigs that will go on standby where costs go to zero. But the margins are not too far off from what they were when the rig was working. So, that's going to change some of the cost structure. It's also going to change some of the revenue per day. So, it's how all those things fit together is really going to be affecting how you model our cost per day and our revenue per day. So I would say that all that is moving significantly in the second quarter and into the third quarter. So there's just a lot of moving pieces in those numbers for the next 2 quarters.

Got it. Understood. And I appreciate all the detail on the pumping restructuring. How are you thinking about your footprint on the drilling side? Have you guys reassessed the number of operating locations, support facilities on the drilling side? Is there any downside, particularly from an operational and a regional standpoint that makes sense, given what could be a lower activity set coming out of this?

Yes. In general, we haven't had to make too many changes in terms of facilities and support structure facilities in drilling. As you can imagine, the Bakken has slowed down significantly for everybody. And so we've made some of the bigger reductions up there. But in general, we were rightsized with the facilities for the number of rigs and remember, we're still working over 100 rigs. So, we still have a fair amount of activity out there today. But with all of our businesses, unfortunately, we're scalable and we'll have to scale because of the downturn we're going through. And as I've mentioned, Q2 is probably the biggest challenge to try to model everything because things are still coming down quickly in Q2, and the cost reductions are right behind the activity.

Yes. Hey Scott, this is Andy Smith. I would say that while we called out more around directional drilling and pressure pumping, certainly, across the board, everyone -- with all units within the organization are looking at their costs and there are costs coming out, certainly at the support level. They're just not to the degree that we call that in pressure pumping.

Got you. And one last one. I missed the SG&A guide, what was that again?

$26 million.

That's for 2Q? Is that a good run rate going forward?

Yes, it will continue to come down from there.

Okay. Thank you.

And your next question comes from the line of Zachary [ph] Zurcher of Tudor Pickering. Please go ahead, your line is open.

Hey, good morning. Thank you. Andy, there's a lot of talk right now about frac holidays over the course of Q2 and your guidance probably reflects that for Q2. But if you look from an industry-wide perspective, do you think Q2 might mark the low point from a U.S. completions activity standpoint? And, we see some element of a balance in the back half, or is maybe the visibility you have today too low to make that assumption?

Yeah. I think the term frac holiday maybe overstating what's going on. I think that completion activity continues to come down. We've got visibility on what our rigs are going to do. And with what we see as overall activity there coming down in the range of 60% or more. I don't see how completion makes a bounce back, certainly not in the third quarter and fourth quarter is still a ways off. But I would say that, your completion activity is still going to be coming down as well. Yes, the DUC inventory is likely to increase. We've got a number of our customers who we completed frac operations in the middle of the pad and then moved on, but there's no intent to bring those wells online right now. So those DUCs will be out there, but I don't think we're going to see people moving on them towards the end of the year unless we get some significant change in commodity prices.

Okay. That's helpful. And it's encouraging that the guidance around EBITDA positive and cash flow positive even over the back half of the year in pressure pumping. Last year I think you retired about 300,000 horsepower. And it sounds like going forward you've gotten the business in a good position around four active spreads. With the rest of the equipment you have, I mean, clearly, demand is way down in 2020, at what point or what do you need to see to go ahead and retire some more equipment over the course of 2020?

At this time, as you mentioned, we took a ride down last year, and we don't have any plans to ride any more equipment down, we wouldn't make those kind of decisions on equipment in any of our businesses until we get through this down cycle and understand what the market looks like on the other side of the down cycle. That's when you would evaluate how much of the equipment is marketable, how much do you think you'll use again. And so it's – we're way too early to make those decisions in the cycle.

All right. Thanks. I’ll turn it back.

And your next question comes from the line of Jeffrey Campbell of Tuohy Brothers. Please go ahead. Your line is open.

Good morning. First, I wanted to say congratulations to Mark on your retirement. And I will miss your commentary each quarter.

Thank you very much. I appreciate that.

Andy, looking at current market struggles we're still starting to see some stickiness with electric frac spreads, a little bit of traction beginning to happen. Just wondering, is Patterson looking toward this technology at any point in the near or the further future?

No. We don't have any plans to do anything in the area of electric frac, we've looked at that both financially and technically, and I'll start with the technical side. We have a control systems company within Patterson-UTI, it's called Current Power. And we have the ability to actually engineering manufacturer, our own control systems for electric frac and all the electrical drive systems, and we've done it for other electric frac companies. But back to the financial piece, we just never thought, we'd get an adequate return on investment. Yes, we see that there are some contracts out there that are sticky, because in order to build some of that equipment, some companies signed up some contracts around that, but we just never felt like the profile of return made sense for us to do that. We're actually more excited about other technologies, and that's using natural gas as a fuel. And when you look at what we do today, we're one of the leading companies in terms of using natural gas as a fuel where you can substitute up to 70% today. And on some of the new engines that are out there that we're looking at, you can substitute up to 85% of the diesel with natural gas. So there's huge cost savings there for the operators. There's also improvements on the ESG side through the dual fuel and it doesn't require the capital outlay of an electric frac system. So we're more excited about that area than electric frac, but we've looked at it.

Okay. Thanks for that. And one other, kind of, high-level question. I was just wondering if there are any specific changes to normal business practices that you've had to employ specifically due to COVID-19, that have emerged as unexpected positives that might prove sticky even after some recovery? Thanks.

So I want to say thanks and congratulations so far to our team that's been managing our risk and our business continuity around this. It's been a huge effort on the HR side, the supply chain side, to try to manage what's happening in all the various states and regions that we work and the recommendations and regulations that are coming through. And also just trying to understand from the CDC, what are the best practices. We think we are managing this well or as well as can be expected. We've only had two positive cases of COVID-19 in the company. One was office based personnel, one was drilling rig based personnel, and we had plans to be able to manage that. So we haven't had any operational disruptions that are directly related to COVID-19. And you got to remember that our workforce in the field for the most part doesn't come from the bigger cities, but comes from the smaller, more rural areas of the country where you have less of the infection rate of the virus. And so I think that helps us out. And then when people rotate to a rig or to a pressure pumping site, they're there for up to two weeks at a time. So we have everybody together there. And then when they go home, we encourage everybody to continue the social distancing when they're on their days off. But so far, it's something that we've been able to manage. And I want to thank our teams and our employees for everything they're doing to try to manage that at the same time.

And your next question comes from the line of John Daniel of Daniel Energy Partners. Please go ahead. Your line is open.

Thank you, and appreciate you putting a little guy in. Mark, also, my congratulations to you. Just while you all appreciate all the support you've given me over the years and wish you the best of luck and hopefully have you a great time.

John, thank you for that, and let congratulate you on your new firm.

Thank you. It's an interesting time to start a firm literally. Andy, in your prepared remarks, you noted efforts to develop remote lender operations. Can you just expand a little bit about what you're doing, when it started and what's involved?

Yeah. We started this effort over a year ago. Looking at the challenges in how frac operations work and where there are opportunities to improve things, both from a performance and efficiency standpoint, but also from an HSE standpoint, and that's an area that we focused on first. We're already controlling the engines, and the industry has been doing that for years. The blender was the next area to look at. And because we have current power, universal pressure pumping and current power, we're able to work together to come up with a solution for that. And we'll start field testing that this year. And so we think that that's an interesting first step in improving the efficiency of the current assets that the industry owns. And we'll continue down the path to try to move that forward.

Okay. Thank you. And then I just have one more. You mentioned shutting down some facilities like a lot of people are doing right now. At some point, the market is going to recover, at least I hope so. When it does, how do you see yourself moving back into the – do you see yourself moving back into those regions? And – or do you just stick sort of with one to two core areas of operations? Just how will that – how will you look at those decisions?

So the way we see this happening, not unlike some other downturns we've had to experience in the past, where we've consolidated into certain facilities to reduce the cost. As the industry comes out of this down cycle and starts to pick up activity, if the activity is not per se, near the region that we're working, we can still support that from the maintenance facility that we have until we get critical mass in a region to reopen a maintenance facility. So it will really be based on if we get back to a critical mass in a certain region, but it doesn't mean we can't work in the other regions where we don't have the maintenance facility.

Is it safe to assume though the profitability on those fleets have to be significantly higher than what you might get in your existing operation? It would seem obvious to me, but just curious.

When you're managing the operations, especially pressure pumping, remotely, and you're moving equipment long distances, you're incurring those costs to move that equipment. And so once you get to a certain number of spreads and the cost to move those spreads, you get to a cost breakover where it makes more sense to roll them back to a maintenance facility that's much closer rather than burn the diesel. So it's really kind of that math that we would look at. So if you get back to two or three spreads in a particular basin, then it's probably worthwhile to reopen a maintenance facility at that point.

Fair enough. Okay, guys. Thank you and good luck this quarter.

Thanks. Good to talk to you.

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

Hey, good morning, guys. And Mark, a special thanks to you for all the years of importing your wisdom and guidance, I think I've known you from almost 20 years now. So sorry to see you retire, but congratulations on your retirement and your wisdom will be lost, but I hope you enjoy your retirement.

James, thank you for those kind remarks. But I think that, Andy, Andy, Ken, Seth and the rest of the team are all very, very capable of managing for the future. So I'm feeling very, very comfortable about my continued investment in Patterson and the continued direction of the company. So just wanted to say that as well. Thank you for your kind words.

Thanks, Mark, and no doubt about that. Andy, a bigger picture question for me, obviously, near-term is going to be tough. But on the other side of this, if we're looking at a U.S. land market that provides less production than it does today. Let's just use, we've been talking at Evercore about 10 million barrels a day and a rig market that perhaps needs 400, 450 rigs, including the 75 or so gas rigs, assuming we do LNG again, but what do you guys think about the market, or are you thinking about the market? I know things are moving fast and the downturn probably is top of mind. But do you think about the other side of this? And what's your business should be scaled for in a -- just a lower market environment going forward?

First off, our liquidity position allows us to think about the other side. So it's good that we can have that conversation this morning.

Sure.

I don't think anybody has a clear view of what the other side looks like, if everything comes back to the same level of activity or if it's some kind of reduced level of activity. But, let's just say, okay, maybe it's a reduced level of activity. I think in that case, especially on the rig side, you see a continuing shift to higher spec and super-spec rigs. You'll have much less, as a percentage of the SCR. And so, I think, that plays in our favor. In terms of the completion side, not sure how that's going to grow back. I mean, there's going to be a number of DUCs that are going to have to be fraced. And so there may be an opportunity to get on DUCs right away as drilling rigs come back on at the same time versus the normal lag with completion behind drilling. But it's one of the reasons we've scaled our pressure pumping business the way we have. We want it to be able to grow, but we're not sure to what level it's going to grow, too. So I don't think we have that kind of visibility or crystal ball to know what level it all comes back to, but I think that we're still a scalable company, and we can adjust to that. Especially on the drilling side, I think it's going to be heavily weighted to the high-spec, super-spec rigs as things come back.

Sure. Remember about that. That’s all I had, guys. Andy, thanks and Mark, again, congrats.

Thank you.

And our next question comes from the line of Blake Gendron of Wolfe Research. Your line is open.

Thanks. Good morning, guys. Appreciate the comments on the standby termination dynamics. It's going to be somewhat noisy to model it from here on out. Also appreciate the fact that fewer rigs on contract, this downturn versus last, so probably more terminations this go around. But that being said, when we think about standby over the next quarter or two, are your forecast or your guidance on the rig count inclusive of some moderate outperformance of the broader industry rig count? And then if we think about terminations, you gave the backlog, you need the number of rigs on term. Is there any way you can educate us on maybe the conversion, the cash conversion as rigs get terminated? Is there a way to think about termination lump sum as a percentage of contract backlog? That would be helpful. Thanks.

Okay. Let's start with a few things. So in terms of our projections on what we think our rig count's doing versus the broader market, I think that in general, we do pick up a little bit of share, just because the market shifts over to the high-spec super-spec rigs is the primary rigs that are going to be working during this downturn. It's because of the term contract coverage. But we don't really look at that way per se. What we're giving you is really based on the direct knowledge of what our E&P customers are going to do with their operations over the second quarter and into the third quarter. So, I think, that's an important point that this is through a lot of discussions with our customers. We have to stay close to the customers right now. And I want to congratulate our teams in all our businesses for doing that. In terms of the early term, these are customer-by-customer decisions. Sometimes things change in the middle of the quarter. We may have one plan right now, two months from now that might change a little bit. So I don't have any good rules for you in terms of how to look at that. But certainly, if there's an early termination, there's likely cash that's coming back to the company. So while the -- losing the rig is not a good guide of cash coming back to the balance sheet in this type of environment is a good guide for us.

Got you. And that's fair, just given the lack of visibility. Just one follow-up on the directional drilling comments, this is a business that you've been moving out substantially and have gotten out ahead of others. We've heard a lot about remote operations. You mentioned it. Clearly, the incumbents are the Schlumberger and Halliburtons of the world. But I'm wondering, just given maybe a concerted shift toward remote operations, whether that's an opportunity for you to take additional share from some of the smaller providers that may not have the same capabilities or scale built up -- specific service. Any high-level commentary would be helpful on that? Thanks.

I'm really excited about all the adjustments that our directional drilling business has made over the last year and into the first quarter of 2020. And we're very excited about the new technology that we were rolling out in the first quarter and it was part of a technology introduction that we did at the annual conference. It was a Joint Society of Petroleum Engineers, International Association of Drilling Contractors. And the uptake for the technology in the field was really growing in the first quarter until things changed on us. So with the new MWD tool, the new motors, sizes and designs that we have out there in the field, things were really moving forward. And my expectation until the market changed was that our directional drilling business was going to see nice growth in 2020 and was going to gain market share because of that. And that was going to be very positive for the returns in that business. Now things have shifted. That directional drilling business will slow down along with the overall broad industry rig count because we work for a broad number of customers out there. But I am very excited about how that business has positioned itself. And with the new technology, that's going to help sustain us. And then that technology also helps us do more remote operations just because of the higher service quality that's happening at the well site with the new technology. We can do more in the area of remote operations and we're making that adjustment in the downturn. We were moving that way anyways, but the down cycle allows you sometimes to move some certain initiatives faster than others. And this is one of them.

Good deal, interested to follow that on the back end of this. Thanks a lot for the color, I'll turn it back.

And our next question comes from the line of Waqar Syed of AltaCorp Capital. Your line is open.

Thank you for taking my question. And first of all, Mark, thank you for all your service and congratulations on your retirement. I've known you for about 15, 20 years and I've always enjoyed your comments and commentary. So we'll miss that going forward. But I do want to note here that since I've known you, you've always talked about returns and cash and shareholder-friendly practices and something that's become a mantra now, but you've been ahead of the curve and you've been speaking about that ever since I've known you. So thank you for that and again, congratulations on your retirement.

Waqar, thank you for that. As you know, that's been my mantra from day one, and I think it will continue to be Patterson's mantra going forward.

Thanks. I know that. It's certainly good to know.

It's in the DNA.

Absolutely. My question, Andy, you've talked about early termination revenues for the second quarter. Any thoughts on one, what they could look like for the third quarter or second half?

I think third quarter is still a little bit too far out there for us to try to estimate what early terms are going to look like at this point or how much cash we get back from that.

Okay. But any portion of that $8 million is for the -- are you allocating all the early term to the quarter or allocating that as based on what it would have looked like had those contracts I been working?

No, that's just based on the contract ending and the cash coming back.

Okay. And then off the low 80s rigs that may be working in the second quarter, how many of those would be on standby?

I don't have that number in front of me.

Okay. And you also adopted today, the Board did the shareholder rights plan. Could you maybe comment on that?

Waqar, I think all of the comments about that really are in that press release. I'd be happy to try to respond to anything else you have. But in our minds, the significant market disruption caused by the rapid and sharp decline in oil prices, exacerbated by the COVID-19 pandemic and other macroeconomic factors, leading a real steep decline in our stock price and increased trading volume made it prudent for us to do that.

Yes. No, it makes sense. And then just last question, Andy, of the four pressure pumping crews that you have, how many of them are in the Northeast and how many in the Texas area?

Well, first of all, I'll circle back on your rig standby question. So, by the end of the second quarter, we expect the number of rigs on standby to be in the low 20s. Then in terms of the split, we're going to be split with two spreads in the Northeast and two working in the south.

Great. Thank you very much.

Thanks.

And your next question comes from the line of Dylan Glosser of Simmons Energy. Your line is open.

Hi, good morning guys. Thanks for squeezing me in. I know it's extremely difficult to predict on what the other side of this collapse would look like, but if you guys had to give a range of where we might see the industry recount trough, what would that be in your opinion? And when would you expect us to hit the bottom?

I don't think we have visibility exactly of when and what the bottom looks like we have visibility that our activity in general is going to come down in the range of 60% or more, but it's hard to know if that's the bottom or if there might be a little bit more than that. So, that's the best visibility that we have so far.

Can I just add to that Andy, it strikes us as really difficult to make accurate predictions, given the macroeconomic and international players, all of whom are apparently going to act on international oil prices. So, given that uncertainty, it's pretty hard just for any company to make a real judgment about what a long-term oil prices or even six months oil prices.

Yeah. Absolutely. And I guess just going off that, I know, it's hard – it would be hard to predict an exact range for this, too. But just as far as the conversations you guys have been having with customers, but out leading edge day rates and where those might be going as we enter 2021. Do you suspect that, we will – I guess, how big – how significant of a decline do you expect there to be in just the leading edge day rates for your super spec rigs?

Well, I think sometimes, history is a good predictor of what can happen in the future. And if you look at the downturn that we had in 2015 and 2016, you see a recurring theme, especially in contract drilling, where contract drilling for high-spec super-spec rigs is a relatively consolidated sector with relative price discipline. And so it doesn't get pushed to cash breakeven. And it didn't back in 2015, 2016. I don't expect that it will get pushed to cash breakeven even in this downturn just because of the relative consolidation and the relative discipline. We're projecting that, that business stays cash positive. Now, what happens to leading edge day rates, it's too early to predict what that is, but my expectation is those will still be a cash flow positive number.

Okay. That's helpful. Thank you. And my last question this is more of a point of clarity. When you guys talked about positive EBITDA and cash flow on the second half of 2020, was that on a consolidated basis, or is that just within pressure pumping that you're referring to?

Yeah. I would say that's both.

Okay. Thanks.

I think we were probably making comments about it in pressure pumping, but I would say it's both.

Okay. Thanks guys. I'll turn it back.

And your next question comes from the line of Chris Buoy of Wells Fargo. Your line is open.

Thanks. Good morning. I just wanted to ask, you guys have been willing to give a little bit more color than other people so far. Are any trends developing in terms of operator type and their behavior? How much visibility different sets are providing, or how much of a decline you see across different types of operator?

Well, first, let me just say that, I think we're able to give more color than some of the other companies you've heard from so far, because we're a drilling contractor. And the drilling contractor historically has always gotten the first call. Whenever an operator wants to start changing their plans and so we have some relative visibility in what's going to happen. And so I think we've been able to give you more color from that respect. And also manage our other businesses in our portfolio because of that market visibility. When I talk to some of our customers, they're all – they all have slightly different playbooks. Some of our customers have some hedges in place. Some hedges are longer than others. Some of our customers work strictly on cash flow. And I also had some conversations with customers here over the last week on what they're doing on their production and their takeaway. We've got some customers that are telling us that they're not having any problem with takeaway from West Texas because of the relationships they have with the pipeline companies. I've got a few customers that are shutting in all their production right now. And I've got customers who are shutting in half their production. So it really depends on the economics of the E&P, what their financial structure is in terms of hedges or their philosophy on how they run their business. So we've got a mix of customers. Just like we talked about in some of the other calls, where you've got the majors, you've got the large publicly traded independents. You've got the large private independents, small private independents. They've all got different playbooks even within those groups of types of customers that we have.

Okay. That's helpful. And then to follow-up on the pressure pumping side, so planning to drop to four fleets and planning to be free cash flow positive or EBITDA positive, sorry, in – well, sorry, both of those in the back half, EBITDA positive in the first half. I imagine you have to make a utilization assumption around that, probably relatively high utilization. Do you have confidence or assurance from the customers that are working those fleets that they plan to keep working continuously, or is there a decent amount of risk that there could be stoppages with those four fleets?

Well, I think it's best if I clarify that we're not planning on high levels of utilization. We're planning on a calendar that has breaks in it. We also have some spot work that we think we'll do within those breaks, but we classify it as a low probability. So when we're doing our projections, I wouldn't say at all that we're counting on high levels of activity. The calendar still has white space in it. And I think we've adequately adjusted our support structure costs to account for that at the same time.

Okay. Thanks for taking my questions.

Thanks.

And your next question comes from the line of Tommy Moll of Stephens. Your line is open.

Good morning and thanks for taking my question.

Hi, Tom.

Good morning.

There's been a lot of focus on your commentary regarding pressure pumping for the second half being both EBITDA and cash flow positive. My follow-up on that theme, what are you assuming for CapEx for that segment in the second half?

So a lot of that CapEx was front-end loaded, some of it carryover from last year. I'll hand it over to Andy Smith. He can give you some more color on that.

Yeah. Hi, Tommy, I mean we did kind of front-end load that CapEx and with a sharp decline in activity. We had some built up inventory. So we're looking at remaining CapEx for the back half of the year, probably in the $8 million type range.

Okay. That's very helpful. Thank you. And then shifting to a broader capital allocation question. You've moved quickly to reduce CapEx overall as well as the dividend. Andy, you mentioned earlier, you don't have any maturities until 2022 and plenty of capacity on an undrawn revolver. So as we go into this downturn, just high level, how do you think about balancing decisions to invest in terms of CapEx decisions to potentially adjust the dividend again to delever or just build cash? Give us a sense of how you're balancing all those priorities?

Yeah. I'll start, and then I'm sure others will want to join in. But as we came into this kind of real sharp decline at the end of March, I think, we like most other industry participants said, okay, well, let's – I think right now, the most valuable thing we have is liquidity. So we prioritize liquidity. And that was our thinking as we went through the last month or two. As things stabilize and we see it maybe a little bit of light at the end of the tunnel and potentially even an upturn, our thinking may change. But I think it's too soon to really call when that will happen and what we'll do at that point in time.

I would guide to that. At the start, the most important thing is to make sure that you have the liquidity you need. Later on, you can be – you can think about what other the choices you have.

Yes. I mean, Tommy, we don't have any concerns around our ability to draw on our line. I mean, or anything like that. We just – again, not really knowing where all this was going to shake out early in March. Yes, we wanted to maintain the flexibility and that liquidity comes flexibility.

Fair enough. Thank you for the answers and I’ll turn it back.

Thank you, ladies and gentlemen. I would now like to turn the call back to Mr. Mark Siegel. Thank you.

Ladies and gentlemen, thank you for joining us on our conference call for the second quarter. And this allows me to say a final thank you to each and every one of you with whom I've had many interactions over many years, and so thank you for all of those. And look forward to seeing you in a personal capacity separately as the time goes by. Thanks, everybody. Bye.

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