Good morning and thank you for joining us for RPC Inc.’s First 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. Instructions will be provided at that time for you to queue up for questions. I would like to advise everyone that this conference call is being recorded. Jim will get us started by reading the forward-looking disclaimer.

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 and reflect a number of known and unknown risks. I’d 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 www.rpc.net. In today’s earnings release and conference call, we’ll also be referring to several non-GAAP measure of operating performance. This 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 issued today 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're calculated. If you've not received our press release for any reason, please visit our website at rpc.net for a copy. I'll now turn the call over to our President and CEO, Ben Palmer.

Thanks, Jim, and thank you for joining our call this morning. RPC's first quarter financial results reflect a strong operating environment similar to the fourth quarter. Although oil and natural gas prices declined earlier this year, manager services remain tight by total standards. The multiyear period of underinvestment by exploration and production companies, coupled with industry discipline, leaves us constructive on the length of the current cycle. The vast majority of our service -- the vast majority of service companies have been using their recovery to replace equipment that was wearing out rather than adding net new capacity. It is our view that this is necessary for the long-term health of the oilfield services industry. We expect to allocate capital over the next several quarters to enhance the service effectiveness of our various lines of businesses, while also improving our ESG profile. Our CFO, Mike Schmit, will discuss the quarter's financial results, after which I will provide closing comments.

Thanks, Ben. I'll start with the first quarter 2023 sequential financial overview. First quarter revenue decreased slightly to $476.6 million from $482 million in the prior quarter. The nominal decrease in revenues was primarily cautious by weather disruptions and a change in job mix in pressure pumping, RPC's largest service line. Cost of revenues during the first quarter also decreased slightly to $305.3 million from $308.6 million in the prior quarter. As a percentage of revenues, cost of revenues remain the same as 64% compared to the prior quarter. Selling, general and administrative expenses increased to $42.2 million in the first quarter of 2023 compared to $38.2 million in the fourth quarter of 2022. This increase was driven by higher expenses that are typically incurred in the first quarter, including payroll taxes and 401(k) employer match. During the first quarter of 2023, RPC also reported a $17.4 million defined benefit pension plan termination charge. During Q2, 2023, we expect to record an additional settlement charge of approximately $1.2 million associated with the final termination of this plan. In connection with the transfer of the planned liabilities to a third-party, RPC made a $4 million cash contribution during the first quarter. Operating profit during the first quarter decreased by 19.3% to $90.7 million from $112.3 million in the prior quarter. Adjusted operating profit was $108 million in the first quarter, a 6.3% decrease compared to $115.2 million in the prior quarter. Adjusted EBITDA also decreased slightly by 3.9% to $132.9 million from $138.4 million in the prior quarter. Our Technical Services revenue -- segment revenues decreased by 1.3% to $452 million. This segment generated $103.5 million of operating profit compared to $110.5 million in the prior quarter. Support services revenues increased by 3.3% during the first quarter of 2023 compared to…

Thanks, Mike. First quarter of 2023 was an excellent quarter for RPC, notwithstanding some minor weather disruptions. While oil and natural gas prices dropped during the quarter, it did not materially impact demand for our services. With oil prices rebounding early in the second quarter, we are optimistic about the ongoing stream of this cycle as the year goes on. A big thank you is warranted to our employees for delivering the results again this quarter. I want to thank our corporate and enterprise surfaces employees, our business unit leaders, our operations managers and our well site employees. All of them are working tirelessly to provide quality services to our customers every day. We obviously look to continue our tradition of generating industry-leading ROIC and returning capital to our shareholders. In the first quarter of 2023, we repurchased 1.1 million shares for approximately $9 million and doubled our cash dividend of $0.04 per share or $8.7 million per quarter. This morning, we announced RPC's Board approved an increase in our share repurchase authorization and declared another cash dividend of $0.04 per share. Over the last decade, RPC has returned over $554 million to shareholders through a combination of dividends and opened market share repurchases. Thanks for joining us this morning. At this time, we're happy to address any questions.

[Operator Instructions] Your first question is from Stephen Gengaro with Stifel. Please go ahead. Your line is open.

Thanks. Good morning, everybody.

Good morning.

I guess a couple of things. You mentioned the expectation to continue to operate 10 fleets throughout the year. Can you give us sort of your perspective on the supply/demand and pricing dynamics in the pressure property market right now?

Stephen, this is Ben. Like we indicated, it's stayed strong. We had some discussions with some customers about pricing. We're working with them to minimize any impact on our results. But there are some changes. There are some -- as typically happens, we're moving around some fleets and things like that to stay busy and maintain our efficiencies in our downtime, but we don't see any big changes at this point in time. So we think it's still, as we indicated, is type by historical standards and we still feel good about where we are.

And when you look at what you see in the order book relative to sort of natural attrition of the fleet, are you seeing much net growth in the overall market over the next three or four quarters?

We see various business information is provided. And as I said in my comments, I think our peers across the oilfield services are doing a pretty good job of trying to not significantly increase capacity. There's certainly new equipment as being what we're doing the same thing, right, but it's typically to replace existing equipment in the work that allow us to maintain our fleet level, while we send other older equipment out for refurb. The equipment that we're removing now, once it comes back in the coming months. There'll be another fleet that will take out of service. So we expect to remain at 10 fleets for the time being. And we're hopeful that others are doing the same thing. We think there's indication if that's the case, there may be temporary periods of where somebody believes that they have extra capacity that they can put an additional fleet in the field for a period of time, but this equipment is wearing out. And you do have to continue spending to maintain. So we're hopeful that, that discipline will remain in place going forward.

Great. Thank you. And just one more quick one. Can you run through the revenue by product line for the first quarter?

Yes, David, sure. This is Jim. The values I'm about to give are the percentage of consolidated RPC revenue, that's comprised by each of these service lines. So our largest in the first quarter 2023 was pressure pumping at 55.6% of revenues. Our second largest service line was downhole tools and motors, which are Thru Tubing Solutions brand that's 22.5% of revenues. Number three is coiled tubing, which is 8.4% of revenues. Number four is rental tools, which is 3.7% of revenues, then comes nitrogen at 2.5% of revenues. Finally, Snubbing which was 1.5% of consolidated RPC revenues for the first quarter.

That's great. Thank you, Jim.

Your next question is from Don Crist at Johnson Rice. Please go ahead. Your line is open.

Good morning, gentlemen. How are you? I wanted to kind of ask a follow-up as to Stephen's question. I know you had a lot of fleets that were as a percentage of your total fleet count that were dedicated in either the Haynesville or the gas basins. How many of those have kind of moved around or been shifted to more oily basins as gas has been a little bit weaker in the first quarter?

Hey, John, this is Jim. Let us correct you a little bit on that. We haven't had fleets working in the Haynesville for a while. We -- starting -- what you might be thinking of is last summer, we reactivated the fleet that was in East Texas, but it's been working in West Texas. So we really have not moved any fleets around. We've still got -- we got two in the Mid-Continent and the rest are in the Permian. So there hasn't been any geographic movement for Wyoming [ph].

But our operating model is that we can move the fleets, as Jim indicated, the fleet from East Texas has done a little bit of work in that area, but more it did in West Texas and from time to time depending upon calendar and opportunities and things like that, some of the one or two of one, typically, the mid-con fleets might do some work closer to West Texas. So that's something that our managers are and sales team work on all the time and you know, what's the optimal placement of the fleets, given opportunities that we're valuing.

Okay. My mistake there. I was thinking some old data. And kind of, talking about the supply chain, I think, I heard you correctly that you're going to refurbish two fleets this year. How does that supply chain look? Is inflation, kind of, subsiding there, or -- and lead times coming down, or is it kind of status quo as to the way that it has been over the past nine months or so where it takes 12 months to get an engine?

Well, I think, it's a little bit too soon to probably say that it's improved significantly. We think, certainly, there are signs that, that may be the case – there is some of the very high demand components we've been planning ahead and making sure that we have that availability before we initiate these reform programs. So it's just something we've had to plan through and coordinate with our many very valuable suppliers and things like that. So -- it hasn't been an issue, but there are long lead times, you just have to plan ahead for us. We've got a plan that we've laid out based on expected activity levels and intensity of activity what we think our equipment needs to be overhauled or refurbished. So we're able to put that planning in place to make the commitments -- put the commitments in place to be able to have the key components available we want to undertake the refurbishment activity. And even when -- even as we have to do the same thing leading into this new tier for equipment that we've recently received and placed in service, we had to several months ago, procure the key components to be able to complete parts of that assembly. So to take a little bit of planning, but I don't know that, again, that we've yet seen any significant let up in the pricing. But I wouldn't be surprised if there's a little bit given some of the volatility we've seen lately.

Okay. I appreciate the color. I'll turn it back. Thank you.

Thank you.

Thanks, Simon.

Your next question is from Derek Podhaizer of Barclays. Please go ahead. Your line is open.

Thanks. Good morning, guys. I just wanted to go back to that

Good morning, Derek.

Changing job. Hi. The changing job mix in pressure pumping. Just if we can expand on that comment? Just more color around, is that a spot market versus dedicated? Is it a customer type, private versus public? Maybe just a little more color on your changing job mix within pressure pumping

Well, I think, you guys can do add-on. I think we refer -- well, weather impacted us a little bit with the job mix, too. We had a little bit less fuel than we provided. You know, there's not a whole lot of margin on the fuel. So it would -- impacted revenue, but didn't have a significant impact on our margins. And that was a little bit of I think that in one case, if they have been an existing customer who changed their mind about whether they want to provide it or not, they may have been a new customer that we would do. The mix of our customers has not really changed significantly. We do have a lot of privates as customers, but we had a nice mix between the public and the private. So it really hasn't changed a lot in the first quarter compared to the fourth quarter last year.

Yes. The comment is probably more referring to Ben mentioned mix as the services provided every single job that's slightly different as to what we're doing. And so -- over asked to do and have depth of the wells and everything. So every job is slightly different, and some jobs are more profitable than others. And so that's probably more rather than the mix of the type of customer. It's more of the specific type of job.

And Derek, this is Jim. I'll jump in, too. Another variable is how much sand we provide versus how much our customers provide. That really didn't change Q4 to Q1; another variable is 24-hour versus 12-hour revenue. We're pretty much maxed out there. That did not change either. So as Ben mentioned, it has to fuel it doesn't. There's nothing else that's meaningful from a macro perspective, i.e., private versus public or any change in what customers are doing. It moves around a little bit, but not a whole lot.

Got you. Okay. That's very helpful. And then maybe just on spot market versus dedicated. I guess, how much percentage of your fleet’s on the spot market versus dedicated? And what are the big differences that you're seeing before between those two markets? It seems like there's a bit of bifurcation between those two markets right now. So any comments around that would be helpful.

So it's about 50/50 spot versus dedicated and dedicated doesn't mean what it meant a long time ago. It means that we have six to nine-month commitments. From our perspective, there's not a lot of discernible difference between those two types of relationships.

Got it. Okay. That's helpful. And then just my last question, and we've been hearing from some of your peers. Moving fleets from the Haynesville and the Permian, and just -- are you seeing that? Are you -- is that putting any pressure on your pricing on the conversation you have with your customers with the threat of being displaced by larger peer. Just any color around fleet movements from the Haynesville into the Permian affecting your operations?

I think it's pretty reasonable to say that the natural gas weakness, the weakness in the price of natural gas is certainly going to slow down some completion, the drilling of the other contracts may not -- the completion will be -- we think there we heard some peers to talk about moving some fleets. It's not that we were in the Haynesville doing diesel, natural gas work anyway. So it's not evident to us on the first quarter. Certainly, at the margin, there's a little less tightness in a place like the Permian, but that just manifests itself in maybe a little more white space in calendars, but it's not -- to us, it's not material at this time.

Our team does a fabulous job of staying up to date across the market. And that's a terrific job of being able to minimize that white space when volatility begins to occur. And I think there has been a little bit more volatility but we respond to that. And we think any impact at this point in time if those changes and the moving around is going to be -- will not be significant.

Got it. Have you had to move some fleets around the Permian to different customers yet?

Yes, we have done a little bit of that. We're in the process of doing a little bit of that, yeah.

That's correct. I think that we're always -- not great. I want to say it's significantly more than normal for us from the last year or so.

Okay, great. Really appreciate the time and color guys. I'll turn it back.

Thank you.

All right. Thanks, Derek.

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

Thank you. Good morning.

Hi, John.

I'd like -- just any – hey Jim. Just a quick question about businesses besides frac, where you have exposure to some of the other basins except the Permian, right? Because we tend to focus on the Permian and frac but -- can you walk us through -- and I'm not looking for numbers here, but just the visibility in the other basins for your other sources, call it, today versus what you had three to six months ago?

John, this is Jim. Thanks for asking questions about something other than pressure pumping. So three toting solutions has a really good market share and really widespread market presence, there's -- they're a good thing to look at. They've talked about some weakness in East Texas and the Haynesville and a little bit of oneness in the Northeast in Pennsylvania, where they have a presence. So that's one thing we've noted in our operational reviews getting ready at quarter end that as said, there's a little bit of weakness in those places, which we would expect that with lower natural gas prices. But at this time, still nothing same and similar to the pressure pumping rate move around from customer to customer.

But would you say that, the -- let's just pick up the Mid-Con or Bakken, do you enjoy the same type of visibility there as you do in the Permian? Just has there been a discernible change, I guess, is another way of thinking about it?

I guess, not discernible enough to – its good question, but not far enough to comment on at this point in time.

Okay. Fair enough. If we go back to six to seven weeks ago when oil prices kind of crapped out, and there was a lot of fear in the market. There was a lot of request from E&P's for some price relief, et cetera and some companies made some concessions and others did it. My question is if when you were going through that process, if you -- if you happen to be in the camp that made some concessions, what was the discussion about -- hey, what if oil prices go back 80, 85? Is there -- do you get -- how quickly can you recapture that, I guess, is the question?

I mean, I guess I'll just make a comment that we're heavier in the sort of spot market and less long-term contracts in some of our competitors. So we can kind of respond more quickly to higher prices. And so we were in as maybe impact some of the others.

And I think to your point, John, I think I don't know I'm sure that was alluded to. The team has been very good at being appropriately aggressive with pricing. So we're ready to make those adjustments when we necessary. We think we're in a good spot relative to those customers. And many -- whatever changes we may have made, we worked really hard with our customers to make it more, maybe change the composition of the job made it less expensive than really being a distant cut and price, right? So it was more like what can we do to reduce their costs. And then for example, that might be then providing a fuel rather than us providing the fuel right. So that particular item, it doesn't have a big impact on us. But again, a very, very appropriate question as you always ask. And -- but working through it and certainly mindful and we all understand that we do need to generate sufficient returns to continue to invest in the business to be able to meet our customers' demand

Right.

John, it probably goes about saying, but we better say it anyway, sentiment today is a whole lot better than it was when prices were lower and growing lower oil prices than where they are today. We also have the ability -- we haven't done this yet, but we certainly maybe signaled to some of our suppliers that we would like to or may need to talk to them about cost structure on that side. What you helpers should that come up?

Fair enough. Okay. Well, thank you for managing that again. Appreciate it.

John, I thought maybe you were calling for some roadside assistance.

Well, I love that actually. Is give them like Employee of the Year award, because he said -- anyways, that's all right.

And 20 there, they go a lot faster.

Glad, you’re okay.

Yes. Thank you very much. Okay. Take care.

Okay, John.

[Operator Instructions] There are no further questions at this time. I will now turn the call over to Jim Landers for closing remarks.

Okay. Thank you. We appreciate everybody who called in to listen this morning, and we appreciate the questions and the conversations. We look forward to talking to everybody soon. Have a good day.

This conference call will be replayed on www.rpc.net within two hours following the completion of this call. This concludes today's conference call. Thank you for your participation. You may now disconnect.