Patterson Uti Energy Inc Q1 FY2021 Earnings Call

Ladies and gentlemen, thank you for standing by. And welcome to the Patterson-UTI Energy First Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. Please be advised that today’s conference is being recorded. Thank you. It is now my pleasure to turn the call over to your host, Mr. Mike Drickamer. Sir, the floor is yours.

Thank you, Sylvia. Good morning. And on behalf of Patterson-UTI Energy, I’d like to welcome you to today’s conference call to discuss our results for the first quarter of 2021. Participating in today’s call will be Andy Hendricks, Chief Executive Officer; and Andy Smith, Chief Financial Officer.

Thanks, Mike. Good morning. And welcome to Patterson-UTI’s first quarter conference call. We are pleased that you can join us today. For the first quarter, revenues and adjusted EBITDA increased sequentially and exceeded our expectations, despite challenges from the extreme winter storm in the Southwest. Both contract drilling and directional drilling posted better-than-expected results, while pressure pumping was impacted by downtime associated with the storm. Excluding the impact from the winter storm, pressure pumping results would have been consistent with our expectations. Crude oil prices trading in a tight band around $60 have been supportive of increasing activity, and looking forward, based on conversations with customers, we now have greater confidence in further improvement in drilling and completion activity. We expect our rig count will reach approximately 80 rigs over the next three months, with most of that growth coming late in the second quarter and early in the third quarter. Additionally, the pricing on most of our currently active rigs has been reset since the beginning of the downturn, and as such, we believe the second quarter margin per day will be the low for this cycle in drilling.

Thanks, Andy. For the first quarter, we reported a net loss of $106 million or $0.50 per share, compared to $0.57 per share previously. Adjusted EBITDA grew 20% sequentially to $35.4 million, supported by a 9% sequential increase in revenues. In contract drilling, our average rig count improved to 69 rigs from 62 in the fourth quarter. We ended the quarter with three idled but contracted rigs, one of which returned to work in early April. The average rig revenue per day for the first quarter was $21,590, which included a $2.3 million benefit from revenue earned during the downturn in 2020, though not recognized at that time due to concerns about collectability. Compared to the fourth quarter, the average rig revenue per day also benefited from a lower proportion of idle but contracted rigs at reduced rates and higher-than-expected revenues from ancillary services.

Across the industry, the U.S. land rig count has nearly doubled over the past nine months. Over this timeframe, private operators have increased their rig count by more than 150%, while publicly traded operators have had a more modest growth rate as they were balancing capital discipline relative to budget in crude oil prices. The pressure on our customers and on the industry to exercise capital discipline and work within cash flow has been growing, and it is a shift for the majority of the years in the U.S. on conventional’s revolution. As we exited 2020 and moved into 2021, we continued to see greater capital discipline from our operators and a more orderly progression in activity. The interesting point is that this capital discipline is relative to the 2021 budgets, which were based on lower commodity prices than we’ve had over the last few months. And I believe that with improving operator cash flow, we will see further increases in activity through the year. This is still in line with capital discipline, as increasing activity can be funded within cash flow. We’re encouraged by this capital discipline across the energy sector that still allows for further increases in industry activity, where premium contractors with superior performance and technology offerings will be rewarded for the value they create for the customers and where there will be opportunity to increase pricing as the industry activates more equipment. Within this environment, as a premium service provider, we are well-positioned. We’re the only drilling contractor in the U.S. with a significant presence in directional drilling. Through the use of technology, be it remote operations or the automation of certain operations, we are uniquely positioned to better integrate directional drilling operations into the drilling rig and improve wellbore quality and performance. We are also well-positioned to benefit from our leadership position in the use of alternative fuels and power sources to help our customers reduce costs and emissions at the well site. For example, we have the ability to substitute cleaner burning natural gas for diesel in many of our drilling rigs and frac spreads. Additionally, we have the ability with our EcoCell lithium battery hybrid energy management system to manage the power generated at the rig more efficiently, thereby reducing fuel consumption and emissions. As well as to further minimize emissions at the well site, we have the ability to run drilling rigs on high-line power from the utility. For more information on these technologies, please refer to our updated Corporate Sustainability report that we published during the first quarter.

Thank you. Your first question comes from the line of Mike Sabella from Bank of America.

Just real quick on the margin guide rate, did you all give it or did I just miss it for Q2?

Mike, what was the question?

Just on the margin guide for drilling in Q2. Did you all give it and I just missed it or…

Yeah. It was $6,200 per day.

$6,200. Okay. So when we think about Q2 and I know, Andy, you mentioned Q2 being the low point for the year. One of your peers is out talking about possibly pushing pricing. You all seem like maybe that’s possible as well. Can we talk about how pricing plays into that, maybe where spot rates are leading edge day rates are today relative to the overall total and where we think they can go to in the second half?

We don’t typically get into what we think they are publicly for competitive reasons. But I’ll tell you there’s still a bit of a range of day rates on the spot price out there. But we believe that as we start to put up more rigs later in the second quarter that we’ll have opportunities for pricing to move up at the end of the second quarter and into the third quarter and then through the rest of the year. And we’ve seen this in other downturns in the past where especially with the super spec rigs that we offer in the industry. As the rig count starts to move up, pricing has the opportunity to move up as well.

Got it. And then just kind of, I guess, a higher level question, you’re several years away from the last big M&A move for the company. As we sit here, kind of the outlook internationally looks a little better. If we think about Patterson over the next couple of years, is there anything internationally you guys are interested in? If not internationally, is there anything in the U.S. you could see kind of fitting well in the portfolio?

I think the best way for me to answer that question is just to say, we maintain a healthy balance sheet. That’s our history. And we try to find opportunities to exercise the strength of our balance sheet when we come out of these cycles and we’ll just have to see what happens at this point.

Understood. Thanks, guys.

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

Hey. Good morning and thank you. In pressure pumping, the Q2 guidance looks really strong. Revenues obviously up huge as you’ll get much better utilization following the winter storm. I’m curious it doesn’t seem like in the Q2 guidance just based on the implied incrementals that there’s a whole lot of pricing uplift baked in there. So I’m curious if you could frame for us if you normalize for some of this weather-related noise and what sort of efficiency improvement you might be seeing from a, however, you want to define it, stages per day metric? And then looking longer term for pressure pumping or maybe exiting 2021, I mean, do you think you can get back to sort of a double-digit gross margin run rate without a whole lot of pricing improvement just as activity continues to trend higher?

Yeah. I think that the pressure pumping sector is starting to become structurally in a better place. We’ve certainly seen attrition through various companies over the last year and it becomes more challenging for companies to put spreads back to work. That being said, we’re going to put another spread back to work towards the end of the second quarter. We may put a couple more out before the end of the year. Every spread we’ve put out has been forecasted on our plan to be accretive and cash flow positive and so that’s the only reason we would put a spread out or even consider putting a spread out. And so when we look at that, we believe that there’s opportunity for pricing to continue to move up through the rest of the year as activity moves up. Having the opportunity to talk about pricing moving up in pressure pumping has been a rare thing. I think the last time I did this was the third quarter of 2017. So the market has had a lot of equipment and a lot of overhang for a few years, but I think it’s tightening up this year. And as we continue to put out some spreads, we see that as accretive and we think that the pricing will move up. In the second quarter, we had the chance to move some pricing on a couple of spreads. I don’t want to get into the numbers. But it was certainly a positive for us, as we haven’t seen that in a while in the industry.

Okay. That’s encouraging. And contract drilling looks like the OpEx guidance, if you just take the revenue less the margin that you guided to, is about $14,700 a day. Could you remind us where you expect that that number to trend as activity continues to trend higher and you get better fixed cost absorption?

I don’t think we’ll see a big change in that number. But I think we’ll have the opportunity to push day rates on rigs towards the end of the year. So I see that, that’s why we’re projecting that we’re going to have margin improvement through the rest of the year and that Q2 is a bottom in this cycle for drilling for the margin per day.

Okay. Good to hear. Thanks, guys.

I’m sorry, you have a question from Waqar Syed from ATB Capital Markets.

Thank you for taking my question. Andy, the incremental demand that you’re seeing both in drilling and pumping, where is it coming from, public E&Ps, private or is it a mix of both? Could you maybe characterize that?

It's been a shift in the landscape. Coming out of the downturn, the first to react were primarily private companies that quickly put up rigs, followed by some of the more agile public firms. Now, some of the larger public companies and even some international oil companies are also considering deploying rigs in the U.S. We're encouraged by these ongoing discussions as we move through this year and into 2022. Our perspective on the market is that, despite the transition, various operators across different categories are expressing interest in increasing rig counts. Importantly, this is within the capital discipline that investors expect from these companies. The initial rig forecasts for 2021 were based on lower commodity prices than what we see now. As a result, customers and operators are experiencing improved cash flows and are reassessing their activity levels. We have many customers currently discussing plans to increase rig deployment throughout the year.

There has been a belief in the industry that approximately 500 rigs are needed for maintenance production and about 220 active pressure pumping crews are required to maintain production levels. Based on your discussions, do you believe that overall industry activity will exceed those numbers as we look toward 2022, or are we likely to remain around those figures?

It’s really an economic discussion that varies by basin, where Permian operators are enhancing their economics and can afford to slightly increase activity and production. WTI prices are rising to a level that is attracting Bakken producers and leading them to add rigs, and the same is happening in South Texas. Therefore, it’s really a basin-specific conversation. Additionally, there’s the Haynesville gas in East Texas and North Louisiana, which operates independently from that. In many instances, it even diverges from Henry Hub commodity prices, as several of our customers there have contracts for LNG export or are drilling to secure land in that region. So, it’s essential to evaluate each basin individually these days and consider the unique economics of each.

Regarding the LNG question, what are the opportunities for additional rig activity related to LNG over the next 12 to 24 months? Have you engaged in any long-term discussions with operators about securing high-end rigs for this purpose?

I would say, overall, activity in that area is steady and slightly increasing, is the best way to characterize that. And I think that while you haven’t seen operators lock up necessarily long-term contracts, the economics for that could improve over the year as well.

Okay. And then just final question on the super-spec rig fleet, given your activity is going to go up quite a bit, some of your peers also seeing that. Where do you think utilization is right now for the super-spec kind of high-end ready rigs? And then whether it could be and when do you see pricing kind of move up in decent increments?

I don’t have the numbers for utilization on super-spec rigs at the moment. However, it's important to note that the super-spec rig is in high demand. Historically, when these rigs begin operating, pricing tends to increase. We might also see a situation towards the end of this year where operators worry about missing out on securing the rig they need, which is beneficial for us.

Absolutely. Great. Thank you very much and appreciate the comments.

And I show no further questions at this time. I will now turn the call back to Mr. Andy Hendricks.

Thanks, Sylvia. I just want to thank everybody at Patterson-UTI for all the great work they did in the first quarter, especially navigating the winter storms, and thanks for the team and a good quarter. Thank you.

Ladies and gentlemen, that does conclude today’s conference. Thank you again for your participation. You may now all disconnect.