(RES)
Q2 2023 Earnings-Transcript
RPC, Inc. misses on earnings expectations. Reported EPS is $0.22 EPS, expectations were $0.36.
Operator: Good morning, and thank you for joining us for RPC Inc.’s Second Quarter 2023 Financial Earnings Conference Call. Today’s call will be hosted by Ben Palmer, President and CEO; and Mike Schmit, Chief Financial Officer. Also hosting is Jim Landers, Vice President of Corporate Services. At this time, all participants are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions]. I would like to advise everyone that this conference call is being recorded. Jim will get us started by reading the forward-looking disclaimer.
Jim Landers: Thank you, and good morning. Before we begin our call today, I want to remind you that in order to talk about our company, we’re going to mention a few things that are not historical facts. Some of the statements that will be made on this call could be forward-looking in nature and reflect a number of known and unknown risks. I would like to refer you to our press release issued today along with our 2022 10-K and other public filings that outline those risks, all of which can be found on RPC’s website at rpc.net. In today’s earnings release and conference call, we’ll be referring to several non-GAAP measures of operating performance. These non-GAAP measures are adjusted net income, adjusted diluted earnings per share, adjusted operating profit, EBITDA and adjusted EBITDA.
We’re using these non-GAAP measures today because they allow us to compare performance consistently over various periods. In addition, RPC is required to use EBITDA to report compliance with financial covenants under our revolving credit facility. Our press release from this morning and our website contain reconciliations of these non-GAAP measures to operating income, net income and diluted earnings per share, which are the most directly comparable GAAP measures. Please review these disclosures if you’re interested in seeing how they are calculated. If you’ve not received our press release for any reason, please visit our website at rpc.net for a copy. I will now turn the call over to our President and CEO, Ben Palmer.
Ben Palmer: Thanks, Jim, and thank you for joining our call this morning. As we announced several weeks ago, RPC acquired Spinnaker, a leading provider of oilfield cementing services in the Permian and Mid-Continent Basins. As we begin the integration of Spinnaker into our operations, we continue to be impressed with the quality of Spinnaker’s management, employees and operations. They bring us some additional relationships with customers that should enable us to deepen existing relationships and improve our marketing efforts and other service lines. Spinnaker runs a great business, yet they can benefit from some of our buying power as well as operating synergies we can provide. Turning to a discussion of RPC’s second quarter.
Business began much like the first quarter, finished but ended with a very challenging June. Since a large percentage of our hydraulic fracturing is spot or partially dedicated work, we were impacted by some customers deferring planned activity to later in the year. This resulted in lower utilization during June and has carried forward into the first part of the third quarter. However, we have already seen signs of improvement on our frac calendar later in the year. While our other business lines have seen some recent pockets of weakness, predominantly in gassy basins, they too are expecting activity to improve. Our participation in the entire suite of completion services provides us with a diversity in both number of customers and customer profile that balances the more heavily concentrated exposure of our fracturing business.
I would like to point out that RPC has initiated the digital transformation designed to improve the company’s operating and cost efficiencies. This extensive and multiyear undertaking aims to change the way we manage maintenance, personnel and equipment as well as our back office functions. We expect this effort will greatly improve our decision-making by providing access to better and more extensive data on a more timely basis. Our CFO, Mike Schmit, will discuss the quarter’s financial results, after which I will provide some closing comments.
Mike Schmit: Thanks, Ben. I’ll start with the second quarter 2023 sequential financial overview. Second quarter revenues decreased to $415.9 million from $476.7 million in the prior quarter. The decrease in revenues was largely driven by pressure pumping customers postponing or curtailing their drilling and completion activities, as Ben mentioned. This was combined with weaker activity levels in the natural gas directive basins impacting many of RPC’s other service lines. Cost of revenues during the second quarter also decreased to $265.8 million from $305.3 million in the prior quarter. As a percentage of revenues, cost of revenues in the second quarter was 63.9%, which was relatively the same as the 64% in the prior quarter.
Selling, general and administrative expenses increased to $43.6 million in the second quarter compared to $42.2 million in the first quarter. This increase included cost of a settlement of a vendor dispute and costs associated with the Spinnaker acquisition, partially offset by a reduction in payroll tax-related costs. In connection with the termination of our pension plan, RPC recorded a noncash pension settlement charge of $911,000 in the second quarter compared to a $17.4 million charge in the prior quarter. We do not anticipate any remaining significant charges in the future quarters associated with the pension plan termination. Operating profit during the second quarter decreased by 9.1% to $82.4 million from $90.7 million in the prior quarter.
Adjusted operating profit was $83.3 million in the second quarter, a 22.9% decrease compared to $108 million in the prior quarter. Adjusted EBITDA also decreased by 17.2% to $110.1 million from $132.9 million in the prior quarter. Our Technical Services segment revenues decreased by 13.7% to $390 million. This segment generated $77 million of operating profit compared to $103.5 million in the prior quarter. Support Services revenues increased by 4.7% during the second quarter. Operating profit was $7.9 million compared to $6.6 million in the prior quarter. Now I’ll discuss our current quarter results compared to the same quarter in the prior year. Results increased to $415.9 million from $375.5 million. Adjusted operating profit increased to $83.3 million from an operating profit of $60.4 million.
Adjusted EBITDA increased to $110.1 million from EBITDA of $80.6 million. These increases were driven by higher customer activity levels and improved pricing, resulting in our adjusted diluted earnings per share improving to $0.30 compared to $0.22 in the same quarter last year. Our Technical Services segment revenues increased 9.5% to $390 million and our segment operating profit increased to $77 million from $59.8 million. Our Support Services segment revenues eased 28.7% to $25.8 million and segment operating profit increased to $7.9 million from $3.3 million. Now I’ll discuss our capital expenditures and horizontal pressure pumping fleet count. Capital expenditures were $39.2 million in the second quarter. This includes new Tier 4 dual fuel equipment that was placed into service during the quarter, while a similar amount of older equipment was sent out for refurbishment.
We currently estimate full-year 2023 capital expenditures to be between $200 million and $250 million excluding the purchase of Spinnaker. In the latter part of the second quarter, we implemented cost reductions, including a small-scale layoff and other cost control measures. This layoff is not expected to significantly impact our ability to respond to customer needs, and we remain staffed to operate 10 horizontal frac fleets. During this period of reduced activity, we intend to closely monitor and manage our cost structure. I’ll now turn it back over to Ben for some closing remarks.
Ben Palmer: Thanks, Mike. Although we’ve encountered a near-term air pocket, we are optimistic for the future if oil prices remain firm. We are already observing encouraging indications from both our frac calendar and our sales teams and other service lines, both point towards a resurgence of activity as the year progresses. This morning, we announced a regular quarterly cash dividend of $0.04 per share as we continue to maintain a conservative capitalization and shareholder-friendly capital return practices. During the second quarter, we did not repurchase any RPC stock because of our self-imposed trading blackout pending the closing of the Spinnaker transaction. We financed this acquisition with cash, which has been building on our balance sheet for several quarters.
Notwithstanding the acquisition of Spinnaker, we will continue to assess our capital allocation alternatives, including share repurchases, dividends, capital expenditures and acquisitions as methods to maximize our returns on invested capital as well as reward our shareholders for their investment in RPC. Thanks for joining us this morning. And at this time, we are happy to address any questions.
Operator: Thank you. [Operator Instructions] We’ll go first to John Daniel at Daniel Energy Partners.
John Daniel: Hey good morning guys. Thank you for including me. I’ll just start with the activity if possible. Can you say how many fleets you’re running today? And then where — based off the calendar, how many fleets you would expect to be running back half of the year?
Ben Palmer: John, this is Ben. Relative to the back half of the year, again, we’re staffed — we’re fully staffed for — we have not — we were able to staff all of our equipment as we have in the last couple of quarters, and we expect to require that later in the year. In the current — I don’t want to provide specific guidance, but in terms of where we are right now, we have had a number of customers that have deferred some of their completion activities until later in the year for various reasons. We’ve had some impact by some acquisitions where some of our customers have — are reassessing their plans and again, pushing their activity later in the year. So we feel — we do feel good about the frac calendar later in the year. We’ve had a lot of discussions and feel that there are reasons for the delays, but us from our customers that they are going to resume their activity.
John Daniel: Fair enough. And on this next question, I’m sure you probably will avoid the granularity, which is fine. But broadly speaking, as you talk to people out in the field, you hear of some fairly significant spot market pricing pressures. And my question is just how broad-based are those across the various service lines? And if concessions have been made, how quickly can you recover those concessions? Just your thoughts.
Ben Palmer: Let me respond and then I’ll let my other two teammates here elaborate. The concessions within fracturing has been more significant than the other service lines. There are some service lines who have given little to no concessions. Some have given minor concessions. But as I indicated, fracturing has been more significantly impacted here in the short term. And in terms of regaining that, that’s very hard to say with oil prices remaining firm and maybe strengthening may — perhaps we’ll have a similar type of strengthening that we had in the early part of ’22 to mid-’22. And I’m hopeful, but we’re not counting on it, but hope that maybe it will firm back up, reasonably quickly as we move into ’24.
John Daniel: Okay. Thank you. And then if I could squeeze one final one in — yes, go ahead.
Jim Landers: Hey John, this is Jim. Anytime there’s an air pocket or any weakness, there are always going to be bad actors who are going to price very aggressively. We’ve seen a little bit of that very recently. But for us, our bias is more towards being idle, been reducing pricing…
John Daniel: Okay, fair enough. And then the last one for me, and I’ll turn it over. With the Spinnaker acquisition, when you start reporting the revenues, is it going to be your #2 or #3 or #4 segment? Can you just throw that out there for us in terms of that?
Ben Palmer: Yes, we’ll give that in a second. It will be four.
Operator: We’ll take our next question from Stephen Gengaro at Stifel.
Stephen Gengaro: Maybe to start, just a follow-up on John’s question. Can you give us the segment breakdown and then maybe slot Spinnaker in there in some manner?
Jim Landers: Sure, Stephen. Thank you for the question. So I’m going to start with actual second quarter. So what I’m about to describe is the percentage of revenue that our top service lines comprise as a percentage of total consolidated RPC revenues. Yes, actual. So number 1 was pressure pumping at 50.5% of revenue. Number 2 was downhole tools, which is our 3 Tubing Solutions service line that was 24.4% of revenue. Number 3 is coiled tubing at 9% of revenue. Number 4 is rental tools, which is in our Support Services segment, but it was 4.4% of consolidated RPC revenue. Number 5 is nitrogen, 3.1% of revenue. Number 6 is snubbing at 1.8% of revenue and Number 7 is cementing at 1.4% of revenue. Now that does not include Spinnaker because we did not own it during the second quarter. If we had owned Spinnaker during the second quarter, cementing would have been our Number 4 service line at 7.4% of consolidated revenues.
Stephen Gengaro: Great. That’s great color. Thank you. When we think about the business, and I think, Jim, you might have just mentioned, there’s been some bad actors in a downturn. We’ve seen, at least on the pressure pumping side, a lot of consolidation, a lot of equipment in the hands of the biggest players. It feels like others have indicated that behavior has been generally better than prior cycles. Are you not seeing that? Or are you talking about maybe some smaller product lines where there’s been some bad actors? I’m just trying to triangulate the commentary?
Jim Landers: No. We would agree my comment related to just some anecdotes of small private pressure pumpers pricing very aggressively over the past month or so. Not — I think we share the opinion everybody else has that market structure is improving in pressure pumping and the larger companies are maintaining discipline as — again, as we are again, we’d rather idle fleets during this time, then take pricing concessions. We do believe this air pocket is just that and it’s temporary. And we’d rather bring back fleets at current pricing and then take concessions and try to fight that back.
Stephen Gengaro: Great. Thank you. And then just one final on the margin front. The decrementals in the quarter, I think were around 40% for company wise. I think that’s right. Maybe a touch higher for — yes, I think that’s about right. How do we think about — like I know there were some headwinds in the quarter from some costs. But how do we think about the margin profile and the decrementals going forward? Should they be more normal versus historical levels? Should they be outsized short term? How do we think about that?
Ben Palmer: Well, these are all very reasonable s. I would say, too, this has come upon us pretty suddenly. As I said, it was kind of mid-to-late June when a lot of this began to unfold. So exactly where it’s all going to lay out, we don’t know. But again, referring back to the comments about we do have specific customer discussions and are quite comfortable that we’re going to have better activity in the latter half. Third quarter could be difficult. We’re still working on, as we always do, but working on filling out the white space and preparing for the more busy fourth quarter. So the decrementals were pretty large. We tend to — when we schedule out. We did have some — we referred to some of our SG&A costs, that settlement of that vendor’s dispute.
We didn’t schedule that out. That was not an insignificant amount. Even though SG&A was relatively flat on a sequential basis, it would have been down if not for that cost and the cost of the Spinnaker acquisition, but we didn’t schedule that out for EBITDA purposes. That’s just more use of the way we do things. But — so I think that — we don’t expect that headwind, something like that in the third quarter. And if that’s not there, certainly, the decrementals would not be as significant. I’m not answering the question directly, but any time you enjoy nice incrementals when you have a nice revenue bounce, and you — you’re impacted by large decrementals when you have a revenue decline. So it will be a challenge, but we’re looking forward to getting through this little air pocket and on to a little more stable times.
Stephen Gengaro: Thanks. I understand there’s a lot of moving pieces, but thanks for the color.
Ben Palmer: Yes, thanks Steve.
Mike Schmit: Thanks.
Operator: We’ll take our next question from Don Crist at Johnson Rice.
Don Crist: Good morning, gentlemen. I just wanted to ask a good question about modeling the Spinnaker acquisition. And I’ll give you two options as to how you want to give it to us. But obviously, cementing was 1.4% of revenue in the second quarter. Either how many fleets you had running — cementing fleets you had running in the second quarter or kind of what the revenue impact would be per fleet of the 18 that you’re adding from Spinnaker, just where we can model properly for Spinnaker coming in, in the second quarter?
Mike Schmit: Yes. We — this is Mike. We had four running in the quarter. And so that will increase pretty significantly after Spinnaker’s in their next quarter.
Ben Palmer: And our existing cementing business performed reasonably comparable. I think the larger Spinnaker, we disclosed that they have 18 spreads at the time of the purchase. They’ve created a little bit more leverage, given their size, but the results were — and revenue was not dissimilar for spread.
Don Crist: Okay. And I’m assuming that the majority of those 18 are running today?
Mike Schmit: Yes.
Don Crist: Okay. That’s all I had. Thank you.
Mike Schmit: Thanks.
Ben Palmer: Yes. I might point out with respect to many of you probably know, the cementing business, we’ve not yet seen any impact there to any significant degree. Cementing tends to not be — it tends to be a little less volatile than fracking. So that’s another benefit of having that little growth opportunity that we see them remaining pretty strong for the next several months.
Operator: We’ll go next to Don Dasher [ph] at Pinnacle.
Unidentified Analyst: Hi, good morning. Just following-up on the Spinnaker deal. Just working through the math, it looks like that business is perhaps a $90 million to $100 million a year business. Is that fair?
Ben Palmer: That’s a good guess.
Unidentified Analyst: Okay. Fair enough.
Ben Palmer: Good calculation.
Unidentified Analyst: Okay. Good. And what’s the margin profile of that on an EBIT basis? I realize there’s cyclicality involved, but kind of on a go-forward basis, what would a reasonable EBIT margin be for that?
Ben Palmer: Well, EBITDA — let me talk to EBITDA margin. It is — as we’ve talked about, it’s a great business. It we do — they were appropriately staffed. I don’t want to say thinly staff, but they were appropriately staffed. So we really don’t have any opportunities to take any cost out. We think we can bring some operational efficiencies, some leverage some of our procurement trucking, that kind of activity that we think can provide some level of incremental benefit. But I would say that the EBITDA margins for this particular cementing business, and our existing business had margins that are similar to what we were experiencing overall within Technical Services, say in the second quarter. It’s pretty good. And we like the fact that the CapEx requirements quite a bit lower from a maintenance CapEx perspective.
Certainly, if we grow it, it will require some CapEx, nothing like fracturing, but from a maintenance CapEx perspective, it has some very nice free cash flow profile.
Unidentified Analyst: Okay. Great. That’s helpful. What were the EBITDA margins for Technical Services in the second quarter?
Jim Landers: Give us a second here, John.
Unidentified Analyst: Yes, that’s fine.
Ben Palmer: 25% to 30%, probably the upper end of that range.
Unidentified Analyst: Okay. Great. And finally, who was the seller of Spinnaker?
Ben Palmer: Catapult was the direct owner. They are not familiar exactly with all the structure, but Natural Gas Partners was the ultimate parent, if you will. I don’t know if that’s the right way to describe it or not, the Catapult. Both entities were great to work with. They did a great job creating that company established in 2014. They’ve grown it nicely, especially over the last three years or so. We’re lucky to have, and glad to have.
Unidentified Analyst: Okay. Great. Was it an auction process?
Ben Palmer: It was, yes. It was.
Unidentified Analyst: It was an auction process. Okay, great. Very good. I appreciate the help.
Ben Palmer: Thank you.
Mike Schmit: Thanks, John.
Operator: [Operator Instructions]. We’ll go next to John Daniel at Daniel Energy Partners.
John Daniel: You guys are very gracious for putting me back in. Thank you.
Ben Palmer: Absolutely, John.
John Daniel: Well, you know it’s early in the morning. So it gives some to do. Hey, on the CapEx budget, it looks like you brought it down to $200 million to $250 million from the original guidance, I think of $250 million to $300 million, which would make sense. I fully understand you haven’t done your 2024 budget yet, but based off what you see today and your expectations, would you envision a spend in ’24 being higher or lower the same as the current guidance for ’23 ballpark?
Jim Landers: John, we’re looking at each other here, trying to think that one out.
John Daniel: Fine. And I know it can change like 10x now, but I’m just curious.
Jim Landers: Yes, probably similar, because as you know, we’re on the schedule of refurbishing frac fleets, and that should continue in 2024. So that’s the junk of cat.
Ben Palmer: We have a road map of our pressure pumping fleet depending upon the level of usage of it, right, when we expect the pumps to wear completely out or be require the refurbishment, the swing factor for next year, I think Jim’s response that it should be similar. I think, on an overall basis, that’s probably true. The swing factor is going to be if we were to take delivery of a new fleet in 2024. As we sit here right now and think about what we hope is going to happen later this year and expect into 2024, I would suspect that probably at the upper end of the current range may be more appropriate, I think we probably will acquire a new fleet sometime in 2024.
John Daniel: Got it. And then the last one for me is when you think about the frac market, which is where the most pronounced spot pricing pressures are. And if you look at the competitive landscape, most of the small people that are bringing the prices down are the two to three fleet type companies, I suspect, some of whom were created with legacy equipment, used equipment during — coming out of the downturn. It would seem the viability of some of those businesses is going to get called into question, because my gut would say that spot pricing doesn’t recover quickly. So you got a bit of a knife fight for several quarters here, which then raises the opportunity set for consolidation. Is that something you would — you envision seeing happening? And would you be willing to participate in that?
Ben Palmer: There’s certainly a lot of discussion about consolidation in terms of buying up some of the smaller players. That’s typically we’ve obviously had — excuse me, a lots of opportunities for that over the years. The question all becomes the condition of the equipment, and that’s something that we kind of have part burn over. I thought more consolidation would be helpful. Obviously, we know we’ve got the one big one that was announced a month or two ago, and I think will help, right, that even the announcement, and then beginning to work together to put the two companies together. I think that should be a net beneficial for the frac industry. So we would certainly encourage it and whether we participate, that’s hard to know.
But looking for opportunities and looking for ways to position ourselves such that we can benefit from. Let me just mention from a pricing perspective that as we were coming out of the downturn in ’20 and ’21, we were very disciplined about trying to understand how we were pricing our jobs and the type of contribution we were receiving from those jobs before we committed to staff new fleets and begin to market new fleets, right? So we didn’t go from — we didn’t want to just put the staff fleets out there and do whatever we had to do to get them working. We try to be very disciplined about the fleets coming back. And that worked very well for us. We have implemented a very similar discipline going the other way, right? If we are not able to generate a minimum level of return.
Obviously, we have to make judgments about what we think the level of activity is going to be in the future. And right now, we think it’s going to be sufficient for us to maintain our current staffing level. But if we — based on the pricing opportunities, if the pricing opportunities are too low, we do not have a problem stacking some fleets at this point where you should have done that. We’re not working our fleets at any whatever price, right? We are remaining disciplined. But we will stack fleets, if we foresee there’s not enough opportunity to keep those fleets busy at a certain level of pricing. So they’re going to remain during that process like we did the upside.
John Daniel: Yes. That’s the benefit of having no debt and enough cash. Some people don’t have that. Okay guys. Thank you.
Ben Palmer: Thank you, John.
Mike Schmit: Thanks John.
Operator: We’ll take our next question from Derek Podhaizer at Barclays.
Derek Podhaizer: Hey, I was wondering if you can give us some examples that give you confidence that activity will recover as the year progresses? Is it just conversations with your customers? Or are you seeing fleets or rigs actually being committed on the calendar?
Ben Palmer: Good question. It’s more firm than that. We’ve had specific conversations with customers given us reasons why they delayed and what their plans are to start back up. Certainly, we were — we’ve had the conversations about that right. Nobody is — customer is not going to tell you three months out that “Hey, three months out from now. I’m not going to work. I have work scheduled, and I’m going to tell you in advance, they’re not going to do that.” So we’ve had conversations. We’re comfortable things could change. If oil prices don’t remain firm, they will reassess their plans. But at this point, if they remain firm, we’re comfortable that things will recover nicely for us.
Derek Podhaizer: Got it. That’s helpful color. So for your mix of fleets between diesel and dual fuel, how has that changed heading into 2024? So by the end of the year, I know you’re refurbing. So by the end of 2024 versus the start of 2023. I’d assume your fleet has increased towards that next-gen dual fuel away from diesel. And with this mix shift lend itself to put more of your fleet on the dedicated market versus spot as we move into 2024?
Ben Palmer: Good question. We are on a spectrum of increasing our DGB in Tier 4 fleet. It has not changed significantly at this point. It is a little bit more ESG-friendly than it was at the beginning of the year. We’re going to continue that process in accordance with our road map. We’re not going to get ahead of ourselves, right? We’re looking at our returns. We’re looking at the age and condition of the equipment. We don’t want to race to get there. We’ll get there when the economics tell us to get there. Our experience with many of our customers are that fuel substitution is somewhat important, not as important as many people talk about, at least for our customers at this point. We think that will change. We think it will become more in demand.
We like our customer mix. We actually — the way we analyze our market, we actually think we have — we call it partially dedicated customers, people who are running four to five or more rigs, they’re maybe not running 10 or 15 or 20, but they have a reasonable amount of activity. And I think that group is a little less, less impressed with or less influenced by the fuel substitution. So we have some pretty fuel-efficient equipment that they tend to like. They like the efficiency as much as they like the ESG benefits. So I think that has served us well, and we’ll continue to serve that market, but we will continue along that pathway that we will have more ESG-friendly equipment as we approach mid ’24 and the end of ’24.
Derek Podhaizer: Got it. Okay. That’s helpful. And then just last for me. I know you mentioned that you expect to acquire a new fleet in 2024. Would you — would that be a new build Tier 4 DGB? Or would that be your entry into e-frac?
Ben Palmer: Good question. This is Ben. I would expect next year, at this point, it would be another DGB. E-frac for us, we’re certainly evaluating that market, staying close to that market. But as I said to our customers, the fuel substitution is not of great importance to them. And I would say the e-fleets are even less important. So it’s something we will eventually get into. Once we’re convinced that there is proven technology and that we have sufficient customer demand for it, we’ll make that commitment. But at this point, we’re still in a wait-and-see mode.
Operator: [Operator Instructions] And we have no further questions at this time. I would like to turn the conference back over to Jim Landers.
Jim Landers: Thank you, and thanks to everybody who called in to listen in. Thanks for the questions. We enjoy the conversation. Hope everybody has a good day, and we’ll see you soon.
Operator: This concludes today’s conference call. I would like to remind everyone that there will be a replay on www.rpc.net within two hours following the completion of this call. Thank you for your participation. You may now disconnect.