Greetings and welcome to Ranger Energy Services Incorporated First Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the presentation. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Mr. Darron Anderson, Chief Executive Officer. Please proceed, sir.

Thank you, operator. Good morning and welcome to Ranger Energy Services' first quarter 2021 earnings conference call. Joining me today is Brandon Blossman, our CFO, who will offer his comments in a moment. First quarter presented some very unique challenges for Ranger. The compounding effect of several activity disruptions that I will talk about in a moment had a material impact on our quarter's performance. However, while we had planned for better results, the fundamentals of our business and performance metrics are all pointing in the right direction as indicated by our Q1 exit rates and the start to Q2.

Great. Thanks, Darron, and good morning to everybody on the call. Let's go ahead and do the standard walkthrough of the first quarter details. First, on the consolidated numbers, Q1 consolidated revenue came in at $38.3 million, down 8% or $3.2 million as compared to Q4's $41.5 million. Consolidated adjusted EBITDA was negative at a $200,000 loss, which was down $3.4 million from Q4's $3.2 million print. Note that in our reported non-adjusted EBITDA, it was higher than our adjusted number by $1.4 million. This delta reflects the inclusion in EBITDA, but not in adjusted EBITDA, of a $1.4 million benefit, reflecting forfeited 401K matching amounts that were expensed in prior periods. Also, note that this quarter's earnings, similar to the previous quarter, did include the additional expense of $1.1 million associated with high-spec rig reactivations. Now under the segment details, starting with revenue, High Spec Rig revenue was flat at $22 million, the result of a slight increase in rig hours offset by an equally slight decrease in composite rig rates. Revenue hours increased from 43,100 hours to 43,200 hours, a less than 1% change. As noted, both a slow January ramp and weather played a role in dampening the Q-over-Q hours increase. More reflective of the actual ramp we saw in activity across Q1 is the metric that Darron had just mentioned. The 22% increase in rig hours we saw at Q1's exit versus Q4's peak hourly run-rate. Q4's average rig count was up 4 rigs to 65, but again, that metric has quite a bit of volatility both due to February's weather disruptions and some swapping out of customers as we moved to more 24-hour work. Quarterly average composite hourly rig rates decreased just slightly again, down 2% or $10 an hour moving from $503 an hour to $493 an hour. Here, the quarter-over-quarter decline in pricing was the result of February's weather disproportionately hurting 24-hour work, leading to a mix shift for the month towards lower rate daylight work. Specifically, for the entirety of Q1, 24-hour work dropped to just 19% of total rig activity as compared to 26% for Q4. However, that sequential drop was driven solely by February's activity. In March, 35% of the rig activity was related to 24-hour work, a recent high point.

Thank you, Brandon. So you will note that we pushed back earnings a couple of weeks this quarter. We had two specific reasons for doing so and expect to return to upfront reporting for Q2. Firstly, we wanted to have a full look at April in order to be able to share some incremental insights in real time. Secondly, we are currently working on multiple smaller M&A transactions. One of which we are hoping to have completed by this earnings call. Unfortunately, this still has not yet closed, but the measurement period for completions is in days, not weeks. Given the likelihood of a couple of transactions closing prior to our next quarter's call, I thought it would be appropriate to share some detail around our current M&A thinking. Our acquisition strategy has been fixed and simple. We are focusing on potential counterparties with top-tier assets, who have a reputation for best-in-class service quality. We are looking at both bolt-ons to our existing service lines and complementary service lines that extend our current core service offerings. Tactically, we believe in being opportunistic. There is a right time and a wrong time in each cycle to be acquisitive, and I'll note that what proved to be the right timing decision in the long run is often counter to consensus thinking at the time.

Our first question comes from Jason Bandel with Evercore ISI.

First question and thanks for all the data points that helped to illustrate the impacts from the winter weather and clearly a better exit rate coming out of Q1 and a nice ramp here in April for rates and hours in High Spec Rigs. But can you quantify further the revenue and EBITDA impact weather had on Q1? And as we think about the revenue progression of Q2, what kind of rig hour or growth do you think you guys can achieve?

Yes. So I don't have the exact number for quantifying the exact weather amount. As I said in my comments, it was a combination of weather and the slow start to January ramping back up. We had some consolidation with our E&P customers that occurred in the fourth quarter. Also, some significant 24-hour rigs were down in the last couple of weeks of December and then fired back up until mid-January. On the wireline side, we had one of our simul frac operations stop until mid-January. The challenges of January combined with the weather and a slow start to January impacted us. As we're coming into Q2, the ramps, if I use the word significant, is probably the right word to use. We're very pleased with what we're seeing right now. We're showing the average rig count I believe was 65 for Q1. As we're sitting here today in April, we're at 72 rigs, with 11 of those 72 rigs working 24 hours. We anticipate a minimum of 3 of those 24-hour rigs going out. So translating that into hours is going to be a very, very nice pickup for Q2. Brandon, do you want to add to that?

So to answer succinctly, we have several numbers for the winter weather impacts that we saw in Q1. The problem is, as Darron highlighted in his prepared comments, we are carrying a lot of additional costs in anticipation of the rig ramp that has occurred. If I include those additional expenses that were sitting idle while the weather delayed our ramp, we get to a really big number for winter weather impact. The range is wide in terms of what metric we actually want to use, and we decided not to quantify it exactly because there would be a paragraph of explanation underneath that specific metric.

Yes, it's always hard to quantify those kind of numbers, especially early on in the recoveries where incremental data is funky. I guess, next question on pricing. It's been a hot topic this earning season as I felt companies work to recapture some of the concessions that were made in the downturn. I know you touched on a little bit in your prepared remarks. But can you talk more about the trends that you're seeing in both rigs and wireline for pricing? On the rig side, is it being driven more by mix as completions come back 24-hour, or is utilization improvement helping as well? And then on the wireline side, what gives you the confidence that you're at a bottom here?

From a timing standpoint, our rigs are probably a quarter ahead of our wireline, from actual price increases, if not a mix issue, just strictly price increases. We started moving prices on rigs actually towards the end of Q4 coming into Q1, and we're starting to see the full impact of that materializing now and are actually preparing for second rounds of that to occur. On the wireline side, we just started to get our first improvement in the quarter of Q1 and towards the back end of the quarter of Q1. So from a timing standpoint, it's about a quarter difference between the two. Definitely on the mix side, we expect to see a fairly decent step-up in composite rates when we report our Q2 numbers. This will be a combination of the actual rate increase and the higher component of mixing in more 24-hour rigs, as their hourly rates are significantly higher for 24-hour rig packages compared to normal daylight packages. So you'll see composite rig rates reported in Q2 and I believe they will move up materially from what we've reported here in Q1.

And then, on the wireline side, Darron?

On the wireline side, I think we are looking at kind of mid-single digits here for our initial price increases and those are tangible. That's why we feel like the pricing has bottomed out, because we've had some success. The market still has too much capacity. So it will be a slower timeline for recovery in pricing, but at least we have come off the bottom.

To Jason's question about how do we know that pricing has bottomed out? Certainly, we don't know absolutely. But as we look through the kind of the fourth quarter, the second half of 2020 and into the first quarter, our math indicates that some competitors are working at breakeven EBITDA at best. This was sustainable in 2020 and early this year with PPP money coming to some of our smaller, more focused competitors. That variable pricing and variable cost pricing is not a sustainable business. So we assume from both macro and micro perspectives that this pricing is not something that can continue to exist in this sector.

And then, the last one for me on simul frac. There's still seems to be some debate around the efficiencies gained and the value created in doing simul frac jobs. Can you touch on what you guys learned from the simul frac trials that you were on and the financial benefit that you achieved from doing simul frac jobs?

I think the efficiencies are real. Again, we did our first trial job starting towards the end of December with one customer. To date, all of our customers have completed simul frac jobs, and they are all adopting them as their go-forward processes. The operators are definitely seeing the benefits of it. From the service side, we did see the benefit from it in Q1, speaking about the efficiencies. From a drilling standpoint, you need a minimum of four wells per pad to be effective for simul frac. The drilling rates hadn't got out in front. We had situations where we would do a simul frac operation, and the next pad we were moving to had only three well pads, which meant we had a crew and a truck that were not needed. That's led over into April as we’ve gotten into May. We feel like with these customers adopting this process as their go-forward strategy, they have adapted their drilling programs to fully utilize simul frac. We have two trucks on location and two crews running simul frac, we're back to our normal type efficiencies and we're getting the benefit. So I think the benefit on the services side is still to come. The E&Ps have recognized that benefit and are adopting this as part of their strategies going forward.

Our next question comes from John Daniel with Daniel Energy.

Good to see the echo the comments before the step-up in April and really glad to see the progress on M&A. I know you can't name names and that's fine. But as you forward Darron, it sounds like the way you're describing it, these are more tuck-ins as opposed to transformative. Do you think the strategy in the near-term will be more tuck-ins, or do you think we'll see a transformative deal? Are you considering the bigger opportunities as well?

Great question. Look, nothing is off the table, John. We have looked at what I would define as small tuck-ins that move the needle modestly to transformative opportunities that could significantly impact the business. The near-term opportunities that we have, while they aren't transformative to Ranger from a material standpoint, they do move the needle with our Mallard business. So we're excited about these opportunities. To answer your question, yes. We continue to look at transformative deals. We hope to get these two across the finish line, but the key word is first. We hope to do multiple transactions. We have positioned our balance sheet for that. We continue to receive a lot of inbound interest from smaller opportunities as well as from companies looking to partner with Ranger and build a strong business together.

There is a universal theme among all the well service companies regarding labor issues. A significant number of them talk about their inability to meet demand due to crew shortages. That clearly provides a backdrop for being more aggressive on pricing. It sounds like you guys are taking the first steps in that direction. The labor situation seems to present a positive outlook for your business for the first time in a long time. Would you care to elaborate? Did I miss anything?

I would agree with you 100%. For the first time, it feels very good. Our strategy of focusing on top-tier clients has paid off, and we first worked for a new super-major in the fourth quarter. As we sit here today, we have four rigs working for them, three of them on a 24-hour basis. Labor is tight. Have we missed some jobs due to crew availability? Yes, we have. Have we raised rates on some lower work that we were doing to move those crews to higher-paying work? Yes. This is a challenge for our program of work. We're loading out on a 24-hour basis, and we know we're staying out working. We're able to recruit crews and get them on board. However, we have turned down some work because we simply did not have crews available.

And John, just for fun, we need a little help on that.

I hope so. Well, I guess my final question is, Darron, you have to strike a balance as leadership between growth versus returns. At this point, what's your internal mandate? Is it to push for that extra 5% incremental rate increase before putting on a rig, or do you prioritize putting out the rig to satisfy customer needs? How are you striking that balance?

One of our objectives is to be a strong cash flow generating organization. To answer your question, I expect that going into Q3, on the rig side, we will be back to pre-downturn revenue levels, matching Q1 2020 type revenue levels, but running fewer rigs and at a higher margin. So that answers your question.

Our next question comes from Daniel Burke with Johnson Rice.

Let me take my little budget on the M&A topic here as well. Darron, you talked about these near-term high probability opportunities existing in a sector where we're kind of at breakeven-ish EBITDA levels entering a recovery cycle. There will be working capital requirements. How do you get comfortable with the cash-generative nature of the deals you're looking at?

Can you take that, Brandon?

Yes. The deals are going to be cash flow accretive likely from day one. Day one means that we've accomplished a good portion of the transition work— not all of it, obviously. But all of this is pre-mapped, and a good portion of it happens on day one. These businesses that we have on the front burner are expected to be cash flow positive. The majority of the consideration for these transactions will be equity, so the cash-out will be minimal, and they will come with their own working capital. There shouldn't be a significant draw on working capital day one, and they should be accretive to all of the metrics that you would expect from a credit perspective. Does that answer your question?

I appreciate the insight as well. It's a kind of dual structure that's helpful to know going into what looks like a pretty imminent probability of closure. So I appreciate that added preview. My last inquiry pivoted back to the model with indications on where the rig business is. Can you talk a little bit about the completions business? It wasn't clear to me if the fits and starts related to the simul frac activity of your customers were fully resolved as we entered April, or whether there are considerations to take into account when thinking about the revenue trajectory on the completions side?

In April, we had one of our core customers with a unit down for two weeks due to the simul frac business. It has since returned to full simul frac operations for the rest of the year. From May forward, we believe that this simul frac business is now in our rearview mirror. Overall, we're seeing as we come out of this downturn, the first response in activity has come from the maintenance side of our well servicing rigs, which continue to grow. We're also starting to see an increase in the activity of our 24-hour rigs. On the completions side, we think that the next level of growth will start to occur here in Q2 and moving into Q3. This matches how operators are prioritizing their spending to keep wells maintained first before ramping up other activities. We will continue to focus on more completion activity, and we anticipate growth in drilling as well. I believe these trends will put our wireline opportunities at a favorable position from both a pricing and activity standpoint.

Thank you. At this time, we have come to the end of our Q&A session. So I would like to turn the call back over to Mr. Anderson for closing comments.

Great. In closing, I just want to thank all of you for your continued support. And as always, I thank our wonderful team members for the great job they do every day, from sales to our corporate office. Operator, thank you. And that ends the call.

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a great day.