NexTier Oilfield Solutions Inc. (NYSE:NEX) Q1 2023 Earnings Call Transcript

NexTier Oilfield Solutions Inc. (NYSE:NEX) Q1 2023 Earnings Call Transcript April 26, 2023

NexTier Oilfield Solutions Inc. beats earnings expectations. Reported EPS is $0.66, expectations were $0.61.

Operator: Good morning, and welcome to the NexTier Oilfield Solutions First Quarter 2023 Conference Call. As a reminder, today’s call is being recorded. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. For opening remarks and introductions, I would like to turn the call over to Mike Sabella, Vice President of Investor Relations for NexTier. Please go ahead, sir.

Mike Sabella: Thank you, Operator. Good morning and welcome to the NexTier Oilfield Solutions earnings conference call to discuss our first quarter 2023 results. With me today are Robert Drummond, President and Chief Executive Officer; Kenny Pucheu, Chief Financial Officer; Matt Gillard, Chief Operating Officer; and Kevin McDonald, Chief Administrative Officer and General Counsel. Before we get started, I would like to direct your attention to the forward-looking statements disclaimer contained in the news release that we issued yesterday afternoon which is currently posted in the Investor Relations section of the company’s website. Our call this morning includes statements that speak to the company’s expectations, outlook, or predictions of the future, which are considered forward-looking statements.

These forward-looking statements are subject to risks and uncertainties, many of which are beyond the company’s control, which could cause our actual results to differ materially from those expressed in or implied by these statements. We undertake no obligation to revise or publicly update any forward-looking statements except as may be required under applicable securities laws. We refer you to NexTier disclosures regarding risk factors and forward-looking statements in our annual report on Form 10-K subsequently filed quarterly reports on Form 10-Q and other Securities and Exchange Commission filings. Additionally, our comments today also include non-GAAP financial measures. Additional details and a reconciliation of the most directly comparable GAAP financial measures are included in our earnings release for the first quarter of 2023, which is posted on our website.

With that, I will turn the call over to Robert Drummond, Chief Executive Officer of NexTier.

Robert Drummond: Thank you, Mike, and thanks to everyone for joining the call. As anticipated the first quarter for NexTier was very strong. We delivered another quarter of improved operational and financial performance, demonstrating both the resiliency and consistency of our strategy. We saw sequential growth in adjusted net income for the 10th consecutive quarter and had another quarter of strong free cash flow. We continue to prioritize a sustained and strong return on capital, and we remain very disciplined, while operating our capital allocation strategy. Despite recent commodity volatility, our 2023 outlook is essentially unchanged from the prior update. Considering our outlook, we continue to believe our share price is significantly undervalued.

We will always invest our capital dollars in the highest return opportunity that we believe will create the most long-term value for our shareholders, including through our sizable shareholder return program. First, for the first quarter, we saw strong operating results even as the quarter was disrupted by winter weather. Adjusted net income of $156 million improved 7% for the prior quarter and was 17% of revenue. Our adjusted net income per diluted share was $0.66. Total revenue of $936 million, was up 7% sequentially and was 47% higher than the same quarter last year. The top line growth was a combination of an increase in pumping hours as well as higher sequential pricing. Adjusted EBITDA of $228 million was 7% higher sequentially and improved for the eighth consecutive quarter.

We saw a full quarter of benefit from the strategic customer repositioning we undertook during the prior quarter, resulting in strong profitability growth. We also generated strong free cash flow of $76 million, even as we saw a large working capital headwind and a front half loaded CapEx budget. We anticipate free cash flow will gather momentum as the year progresses and we will still expect to generate approximately $500 million in 2023, which is a free cash flow yield of over 20% based on current market capitalization. During Q1, we repurchased almost six million shares for $53 million under our $250 million shareholder return program funded entirely with free cash flow. And our adjusted annualized return on invested capital, excluding one-time tax items was 50% for the quarter.

We continue to generate returns well ahead of our peer group. Industry utilization remains very high and we expect to remain sold out. Oil basin activity is supported by a commodity price that is more than sufficient for our customers to generate strong returns. Unlike past cycles, our customers are looking through near-term commodity noise towards a long-term outlook that remains unchanged from our prior update. Their consistency throughout this period of oil price volatility demonstrates the discipline that is enabled by positive global oil supply and demand macro. We expect our sectors to demonstrate in maturity and discipline to continue and for U.S. land frac activity to remain strong in 2023 and beyond. Considering our stable customer base combined with the current oil price outlook, we still do not anticipate we will need to change our pricing strategy.

Natural gas basin demand did soften as expected as the quarter progressed, with industry activity in the primary gas basins down roughly six fleets since the start of the year. Consistent with our prior expectations linked to historic responses to natural gas cycles, we believe there are likely another eight fleets that could be released in natural gas basins, as the commodity seeks balance. The fleets that are most vulnerable are those that are underperforming and those that are working in the spot market. We have very little exposure to the spot market and oil or natural gas basins and our operational performance has been very strong. As such, we should remain relatively insulated from the temporary shuffle of competitive frac fleets resulting from lower near-term natural gas prices.

At NexTier, we’ve yet to see any of our dedicated fleets released by our customers in either oil or natural gas basins. This speaks volumes about our service quality, as well as the quality of our customers and the partnerships we’ve built together. The value created by our wellsite integration strategy has never been more important. And all that is to say, we’ve seen very little change in our business since our previous update and we continue to be encouraged by our outlook as we see the overall frac market operating at near capacity into 2024. By and large, the recent noise and spot market activity appears to be a function of the expected relocation of some fleets into oil basins from natural gas basins. Our view is that the supply and demand balance in U.S. frac will allow these relocated fleets to find new spot work with multiple partners.

Over the long-term, we still believe global oil production will need to increase materially to meet demand forecasts and the call on U.S. shale to grow production will only grow louder. On the natural gas side, LNG capacity additions through 2025 have the potential to create significant demand for incremental frac fleets. We still see U.S. shale struggling to meet both of these calls in tandem given constraints around equipment and capital with the availability of frac equipment likely remaining bottlenecked. We have been very transparent in our view that these supply chains will continue to impact working capacity, and we do not see the situation fully correcting itself until at least mid-2024. This is true for both maintenance and new builds.

We continue to be flexible with our fleet configuration, and are committed to converting our fleet to natural gas powered in the most responsible manner over time. In terms of fleet configuration, we are always pursuing avenues to deploy our horsepower to the best unit level economics and maximizing the returns on our available horsepower is our priority. In response to recent market volatility and fluctuations in the spot market, we’ve already chosen to redistribute one fleet worth of pumps to supplement our best customers in other basins rather than lower our returns, and we see further opportunities to replicate this strategy. In addition, as we stated in our last earnings call, we still expect to retire at least 150,000 horsepower from the start of 2023 through the middle of 2024, rather than invest in maintenance on low-return diesel fuel pumps.

We have already started this process and our deployed capacity today has fallen by 20,000 horsepower relative to the start of the year, as we remove our highest-cost assets. We believe these responsible actions by us and others indicate sector maturity. On the transition front, we are always looking for the most capital-efficient ways to make progress on our electric fleet and natural gas transition strategy. Our CapEx guidance of 8% to 9% of revenue always budgeted for a second equally in addition to the one we had previously announced. And to that end, we recently saw an opportunity to purchase around 20,000 horsepower of electric pumps as replacement for some recently retired diesel equipment. This readily available equipment was from the inventory of a known OEM with proven technology that we have been field testing since 2021.

These assets will allow us to earn a strong return while we accelerate the transition of one of our existing customers to eFrac technology without increasing our overall frac capacity. We now expect to have two customers utilizing eFrac technology by Q3, as we continue to act on our transition plan, while remaining in our capital allocation framework. For clarity, one fleet was previously announced but delayed from January due to supply chain delays and we’re now expecting to take delivery of this fleet by the third quarter. The newly acquired horsepower is replacement for recently retired equipment. We have a high conviction that our steady capital deployment strategy will be the most efficient path to maximizing long-term returns. Even after the delivery of all these electric newbuild pumps, our horsepower by mid-year will be flat with where we started the year.

Considering supply chain and capital constraints, winning this cycle will require service quality differentiation. Our pioneering Power Solutions natural gas fueling business is nearing its two-year commercial anniversary and remains one of our most valuable assets and we are encouraged by recent third-party transaction valuations. We have a big head start with respect to value capture potential from this offering. Since inception Power Solutions has already displaced over 33 million gallons of diesel and created as much as $100 million in fuel cost savings. Our recent substitution rates have been 25% higher versus fleets using third-party CMG providers, increasing the fuel cost savings of our customers and thereby elevating the value of both our Power Solutions business and our dual fuel frac fleets.

The entire business is managed on our centralized NexHub Digital Center, improving visibility to us and our customers. We have organically scaled Power Solutions in the Permian Basin to over 45 million cubic feet per day of compression capacity with a sold-out CNG fleet capacity to fuel 11 to 12 natural gas-powered frac fleets. This scale will increase by more than 50% by year-end. Our proprietary technology addresses both the equipment reliability issues plaguing others in the industry, while also delivering a patent-pending approach that significantly reduces hurdles to using field gas. Our platform is far more than just the CNG transportation business. Our success has been so apparent that we recently started gas deliveries to our first third-party frac well site in early Q1, a large electric frac fleet where gas reliability is critical and where demand exceeds most, if not all, other gas consuming fleets on the market.

The E&P customer had experience with Power Solutions and several other fuel providers and only trusted this challenging operation to NexTier. We will continue to evolve and build on these prior successes and maintain our position as a leader in oilfield natural gas services. We believe our product offering is best-in-class and difficult to replicate, which should give us a sustained advantage in the coming years and increase our capability to capture, a greater portion of the growing fuel cost arbitrage. New to NexTier conference calls, let me introduce our Chief Operating Officer, Matt Gillard. Matt joined the NexTier team in the summer of 2021, and has been critical to making NexTier a top-tier service provider and one that our customers know they can rely on to help maximize their returns.

Matt, to you.

Matt Gillard: Thank you, Robert. And to those on the call, I look forward to increasing our engagement over the coming years. As Robert mentioned, I was lucky to receive a call to join NexTier just over 18 months ago, and it’s been a fantastic and rewarding journey so far. I am very excited to join the public dialogue on frac, at a pivotal time for our industry. Since I joined the company, we have used our well site integration strategy, to differentiate ourselves from the more commoditized service providers, by looking for ways to elevate the returns for both our customers and NexTier investors. We have been extremely capital efficient through this process. Operational excellence is key. We have designed our strategy, to lower the total cost to complete a well lower emissions and raise the efficiency of the completions process, all on our NexHub Digital platform.

Value creation for NexTier and our customers, is the core of our integration strategy. This differs from competing strategies to simply bundle non-complementary services, offer discounts and transfer of value. While our pricing strategy remains unchanged, we are constantly looking for ways to help our customers improve their financial returns. For our customers, aligning themselves with a frac service provider, to value service quality, safety and efficiency will absolutely improve the capital returns of their own operation. Horizontally integrating our dual fuel frac fleets, with our natural gas fueling, our wireline and our last mile logistics business, creates significant value. On average, we believe, we pumped 20% more hours per fleet, relative to jobs where the customer hires third parties for these services.

This lowers the lateral footage completion cost and reduces time to production. We have done this while also managing industry-leading returns for our shareholders. And perhaps most importantly, our wellsite integration strategy allows us to further ingrain our safety culture to more of the services around our frac fleet. Keeping our employees safe, is always the highest priority for NexTier. We have delivered industry-leading safety results, across all product lines which matters deeply in our customers’ decision-making process. Besides our wellsite integration strategy, we are constantly looking for ways to use technology to further improve the well completion process. We were industry leaders in the evolution of using natural gas, as a fuel source for frac.

Our digital sensor has significantly lowered the cost to maintain our fleets and optimize our logistics. And our reservoir technologies, maximize the capital efficiency of completion designs. With respect to reservoir technology, growing challenges around well productivity are well understood. We believe our engineering team is one of the best equipped in the oilfields, to help address reservoir efficiency challenges by optimizing completion design. Our IntelliStim technology portfolio, offers significant improvements over past technology offerings. We have seen considerable uptake in a number of technologies over the last six months, most notably our fiber optic monitoring, and lateral science services. We combine readily available drilling data, with real-time completion data to adjust completion designs on the fly.

These technologies have massive potential to create value. And our team of engineers, is on the frontline working with our customers to understand the best path forward. We understand the value we are creating through these services, and we see significant potential to use our technologies to improve returns for both our investors and our customers. We have used our strategy, to align ourselves with like-minded customers, that are looking to maximize their own capital efficiency. Our customers understand the value that we bring to the partnership and are rewarding us with their loyalty. More than 75% of our fleets are working for long-term customers, that we have worked for more than two years. Our relatively minimal spot exposure, is a function of top-quality service and a like-minded customer base and is constantly looking to work with us on process improvement.

We use our operational excellence and technologies to create sticky relationships to fully align the goals of NexTier and the customer. These long-term relationships should lead to a more stable operating environment for our company at all points in the cycle. Capital efficiency has never been more important in our sector. Helping our customers maximize their returns is a very high priority and the best path to also maximizing our own returns. The frac industry has undergone a massive shift over the past several years. The commoditized service offerings from prior cycles are no longer a reality. We are already seeing bifurcation between the high-end and low-end competitors. Less efficient service providers will struggle to compete and we believe the differentiation will become more obvious in the coming years.

And with that I will turn it over to Kenny.

Kenny Pucheu: Thanks, Matt. First quarter revenue totaled $936 million compared to $871 million in the fourth quarter, up 7% sequentially as higher net service pricing more than offset winter weather disruptions. Execution was strong to start the year with very little downtime that sometimes occurs as the industry restarts from the holidays. Despite weather disruptions in early February, our operations performed at a very high rate throughout Q1, with March being the best month in company history. Adjusted net income was $156 million in Q1, up 7% from the prior quarter and totaling 17% of revenue. Our adjusted net income per diluted share was $0.66. Total first quarter adjusted EBITDA was $228 million, an improvement from $213 million last quarter.

Profitability improved even as we saw higher seasonal expenses that are typical in Q1. Profitability was up sequentially on several factors. First, we benefited from a full quarter of a shift in work to higher efficiency, higher margin jobs with customers that allow us to increase our pumping hours, with less costly downtime. Second, we remain very focused on cost control. Our gross profit margin was up 65 basis points compared to Q4, while our adjusted SG&A as a percentage of revenue improved once again. We will be very diligent with our costs even as we look to continue to grow the top line. Third was on pricing. We saw another round of pricing resets and very favorable customer repositioning to start the New Year. This was a function of the strong macro and high-quality dedicated fleet operations.

In our Completion Services segment, first quarter revenue totaled $896 million, compared to $830 million in the fourth quarter, a sequential increase of approximately 8%. Completion Services segment gross profit improved to $253 million on higher revenues and higher margins. In our Well Construction and Intervention Services segment, first quarter revenue totaled $40 million, a slight decrease compared to $41 million in the fourth quarter. Gross profit totaled $9 million, a decrease from $10 million in the fourth quarter on less favorable job mix. First quarter selling, general and administrative expense totaled $40 million compared to $37 million in the fourth quarter. Excluding management net adjustments of $10 million, adjusted SG&A expense totaled $30 million.

During the first quarter, we recognized a $107 million non-cash tax benefit related to the partial release of a valuation allowance on our deferred tax assets. This release reflects improved market conditions and our expectation to utilize these deferred tax assets over the next several years. EBITDA for this first quarter was $218 million. When excluding management net adjustments of $10 million, adjusted EBITDA for the first quarter was $228 million. Management adjustments include $9 million in stock comp with other items totaling the net of $1 million, which are nonrecurring in nature. Adjusted net income of $156 million includes a management adjustment for the release of the tax benefit of $107 million. Now on the balance sheet. We exited the first quarter with $219 million in cash, up slightly compared to the fourth quarter.

We exited the first quarter with total available liquidity of $631 million. Our liquidity was comprised of cash of $219 million and $412 million available on our asset-based credit facility, which remains undrawn. Total debt at the end of the first quarter was $358 million, net of debt discounts and deferred financing costs and excluding finance lease obligations. We have no term loan maturities until 2025. Net debt at the end of the first quarter was approximately $139 million, down slightly from the end of the fourth quarter. Our share repurchases were funded entirely with our free cash flow during the quarter. Cash flow from operating activities was $173 million. Profitability strengthened once again with cash flow impacted by $45 million in working capital headwinds with the first quarter of the year typically requiring heavy working capital needs.

Our cash used in investing activities was $97 million during the first quarter. CapEx totaled $99 million, mostly driven by normal maintenance, funding for the transition of our frac fleet to natural gas powered as well as investments in our wellsite integration strategy, including growth CapEx for both power solutions and last-mile logistics. We also made investments in ancillary equipment around our frac fleet that should improve frac efficiency. This resulted in free cash flow of $76 million and we anticipate free cash flow will accelerate significantly as we progress throughout the year. In the second quarter, we have already funded the final earn-out payment on the Alamo transaction of $40 million, which will be a headwind to free cash flow in the period.

This was the final earn-out payment associated with that transaction. We continue to see a strong outlook and the investments we have made have positioned us for success at all points in the cycle. Our priorities for high liquidity and low leverage, allows us to be nimble and opportunistic. We are on a path to zero net debt and we fully intend to reach that goal in 2023. The timing remains dependent on the cadence of our shareholder return and our strategic M&A programs throughout the remainder of the year. Positioning the company to be ready to capitalize on opportunistic investment opportunities at all points in the cycle is one of the key components of our capital allocation strategy. A strong balance sheet is core to this execution. At the end of Q1, we had roughly $84 million remaining on our commitment to return at least $250 million to shareholders by the end of 2023.

We reiterate our goal to generate approximately $500 million of free cash flow in 2023. This will leave us with around $200 million in unallocated capital and we continue to look for the highest return investment opportunities, including potential M&A. We currently have a nonbinding letter of intent in place that would utilize about half of this expected 2023 unallocated capital value. Dependent upon final agreement, the consideration may include cash and equity with the equity component potentially comprising of about half of the value. This transaction if successfully closed, we’ll expand our wellsite integration service offering and we expect that it would significantly improve our capital efficiency and would be accretive to our earnings per share even beyond other uses of capital such as expanding our shareholder return program.

This transaction could close within the next 90 days. It is possible we could also execute additional LOIs for other transactions that would add complementary services over the next 90 days. All of these potential deals that we see at this time would fit within our $200 million of unallocated capital for strategic M&A and we expect to execute on our stock buyback program throughout this process. We have a very strong M&A track record and we view this to be a core strength of our management team. We have already passed on several transactions that we did not see as accretive for investors. And if no attractive deals are found, we can pivot to use the cash to further strengthen our balance sheet or expand the shareholder return program. Now on the outlook.

We continue to see solid profitability and March set us up at a good run rate as we entered the second quarter. Further, the second quarter should not have the same weather disruptions that we saw in Q1. For the second quarter, we expect moderate sequential revenue growth with adjusted EBITDA expected to improve once again. We reiterate our CapEx budget at 8% to 9% of revenue for the year. We still expect our budget to be first half weighted and expect CapEx to decline in the back half as we plan to invest early in the year to maximize returns. Outside of the investments we are making to transition our horsepower to natural gas powered, over one-third of our CapEx is targeting high-return projects outside of pure horsepower investments. These investments are core to our results and we continue to see growing returns and free cash flow as they elevate the efficiency of our frac operations.

We see a very strong free cash flow build through 2023 which gives us optionality within our capital allocation framework. Considering what we know today, we do not expect to see a degradation in our operating results in the second half of the year relative to the first half with fundamentals implying consistent and resilient financial performance. As we have demonstrated, our focus is on maximizing value for our customers, our investors, and our employees. I’ll now turn it back to Robert for closing remarks.

Robert Drummond: Thank you, Matt and Kenny. The oilfield services industry, and more specifically, the US land pressure pumpers have shown great discipline as this current cycle has unfolded. We expect capital and pricing discipline will be rewarded and only downside if we return to past strategies. And next year we will continue to lead the way. Now, let me close with a few key takeaways. First, we’ve been saying for some time that this cycle would be different. This is true in many ways. High-quality service providers will be rewarded and when our customers are capital-constrained the value of service quality grows. This should lead to a bifurcation in returns amongst the oilfield service providers. The industry is no longer commoditized as it was in the past.

Our wellsite integration strategy should give us a sustainable advantage as we help our customers maximize their returns without sacrificing our own. Second, demand for our services remains strong and should for the long-term. Our customers have stayed committed to the constructive outlook for global oil demand and absent a more severe macro event that we experienced with the recent banking crisis here we do not expect a material change in their behavior. This is very much a function of a more mature US shale oil and gas sector that does not respond as aggressively to commodity volatility as it did in prior cycles. Finally, we see capital discipline lengthening the period for strong returns for oilfield service companies. We’ve been a factor in shifting the industry focus back to returns and free cash flow and we have a strong conviction that our capital allocation strategy is a winning formula that will maximize the value for our investors throughout the cycle.

We see a reward for remaining disciplined and no reward for returning to the same playbook the industry followed last cycle. The best path forward to us is obvious. With that we’d now like to open the line for Q&A. Thank you.

Q&A Session

Operator: We will now begin the question-and-answer session. Our first question comes from Arun Jayaram with JPMorgan. Please go ahead.

Arun Jayaram: Yes, good morning gentlemen. I was wondering if we could start and maybe elaborate on kind of trends that you’re seeing within Power Solutions. We understand that — and maybe you could discuss maybe the competitive balance because one of your peers is now moving into that segment. I think you’re on 11 to 12 fleets today that could be up 50% by yearend. And maybe just help us think about the earnings power of this segment as we move through into next year?

Robert Drummond: Well, thank you for the question Arun. Yes, I think that that’s a great question focusing on what we think is a very valuable asset to the company. We’re a couple of years into it now and when you look at the fuel arbitrage value between diesel and natural gas, that’s out there to be had besides the fact of being able to deliver your own compressed natural gas to your fleet. The integration between the frac fleet and the Power Solutions part of the business creates a lot of value in the sense that you get higher displacement for natural gas to diesel. We have been measured in our growth despite huge demand for the product outside of our own fleets because we wanted first to supply our own. The benefits in the P&L of the Power Solutions business has to compete on its individual P&L profitability for capital within the company.

But when you take into account the benefit of that is to the frac profitability, it’s really a homerun. And that’s the reason we continue to fund it to the level that we have. I’m going to ask Kenny to comment a little bit about that in a second, but for us we believe that our first venture that I mentioned in the prepared remarks into the market outside of our own fleets is indicative that the customers are seeing the value of that. And we foresee in the future within our capital allocation structure which is largely funding things like this to continue to fund growth in this service. And we mentioned that we do have some patent-pending technology at the wellsite. What the customers like about our offering is that it can preferentially use their field gas through that technology at the wellsite.

And when optimal for both of us, we can use the CNG flow through it. I think that’s something that differentiates us from everything else that’s out there that our customers really like. We see the demand discontinuing. Kenny?

Kenny Pucheu: Yeah. Good morning, Arun. So to answer your question on the value that’s created for the company, I think I’ll just start off with this. We do not report the business separately for several reasons. But I will say this we’ve been funding Power Solutions since 2021. And in 2023 for example, we have nearly $50 million of CapEx that we’re funding for that business as we continue to grow it. It’s part of that high return CapEx budget is a significant part of that. And the way we look at Power Solutions business, we’ve always underwritten with kind of a two to three year payback. And with the success of the platform as Robert mentioned the higher diesel substitution and the recent gas and diesel price dislocation, we’re seeing strong financial performance from the group and very accretive margins to the enterprise.

We’re really happy with these investments we’ve made over the past two years and we are funding it basically as quickly as we get our hands on the kit.

Arun Jayaram: Great. That’s helpful. Maybe my follow-up is for Robert. Robert, one of the themes in earnings season is this bifurcation in the frac market between call it premium providers such as NEX. One of the big investor debates Robert is some of the North American service companies over earning relative to a more normalized view of the world. We’re seeing some day rates come down on land rigs and gas basins. Same thing in OCTG. What’s your assessment — EBITDA per fleet today for most premium operators in that mid-20s range. How do you think about the resiliency of those types of margins in an environment where we could have 14 fleets idle in the near term? And you highlighted very, very strong returns on capital.

Robert Drummond: Good question. A lot of things in there. I would just say are we over earning. I mean it’s hard for me to even to understand I guess because we’re still at 17% kind of EPS earnings. And we in the process not only us, but the sector of funding a transition from diesel as a fuel to natural gas as a fuel. And in that process creating $10 million or maybe even $15 million annually per fleet of value for us and our customer who is funding our services. I don’t think — I think it’s important for everybody to realize that we need earnings levels that allow us to continue to do that funding. Which we think — and we’ve been running kind of the math on it how long does it take to convert the fleet, which I think everybody is on a path to try to do to be 100% natural gas powered or fueled in the future?

And that’s a six, seven, eight year kind of path that requires solid returns for us to be able to do that and maintain our capital allocation and cash return to our shareholder base. So I think our customers appreciate that. I think that the margins now that we’re kind of getting to and the earnings are balancing out nicely with where they’re at I think. And I think it’s a win-win if we can continue to do it and continue to invest and to bring the fleet to a lower emission more value-creating scenario. So regarding the part about supply and demand and a few fleets loose on the market, I kind of want to go into that a bit and talk about the macro. I think from what we guided during the last earnings call until now, we’re still talking about a near-term narrative related to recession in the US natural gas commodity price versus the structural global owner supply that is a long-term outlook.

And I think we have seen gas prices evolve as we had predicted and the corresponding reduction in gas fleets. But additional to that the banking crisis occurred and led to some short-term oil price volatility that now has since recovered. But even through all of that, the horizontal drilling rig count since January had only dropped by 14, which is only 2%. And the DUC count has remained flat. So the bottom line is at the end of Q1 or at the end of Q4, we had made a case that the market was actually undersupplied by 20 frac fleets. And since then with the commodity bounce back and forth, we think that the market has ended Q1 in a balanced state. So from here out, how do you keep that in balance? I think you have basically the need to account for every new fleet add with one out through attrition.

And we’ve been boisterous about saying that we expected to see about 10% of the fleets at attrit during this year, which is about 23 frac fleets on the current kind of 280, which balances very closely with the new build adds that we see coming into the market. So I think that that demonstrates a very balanced market coming off of 2022, which was perhaps the most underbalanced market that I’ve ever seen in frac in my career. So all I would say there is that’s very supportive for our margins to stay the same as we move into the back half of the year. Even in an environment where the spot market is very volatile associated with the movement of gas fleets from the gas basins to oil. I guess, I’d sum all that up by saying we’re just going to trust the macro assessment and we’re not going to get caught up in that shuffle that’s going on a little while in the spot market.

Arun Jayaram: Thank you very much.

Operator: Our next question comes from Derek Podhaizer with Barclays. Please go ahead.

Derek Podhaizer: Hey, good morning guys. I wanted to go back to your comments around redistributing that one fleet worth of pumps. Can you help — can you walk us through that fleet progression? Spot market fleet assuming it was a Tier 2 diesel, customer comes to you asking for pricing concessions you’re not ready to do that. You move the fleet to your other current active fleets to beef up those fleets. I mean, is this the forced attrition that we’re starting to see unfold in the marketplace? Your peer made a similar comment. And importantly are you getting paid for these pumps that go to your different customers? I think just if you can unpack that and give us some more color as to the progression of that fleet and why you chose to redistribute it. It would also sound like you’re also taking stuff out of the market. I think this is an important piece of this disciplined new playbook starting to unfold here.

Robert Drummond: Yeah. Thanks Derek. Look I would just say — I’m going to ask Matt to answer a little bit of that question but it’s more or less that the spot market when there’s a big shuffle going on like we’ve been talking about gas to oil, it can be very volatile. And for a little while as things get repositioned, we just decided not to play in that arena. It was a fleet — we’ve got a very low participation in the spot market in general so we just pulled one of the two or three that we had in the spot market out to reallocate in a manner that was more effective to our profitability. Matt, put a little color on it, please.

Matt Gillard: Okay. So thanks, Robert. As Robert mentioned, we have limited exposure to the spot market already. But we did make that decision to take that fleet out of operations when it began to fall below our efficiency and return expectations. But I think just to add some more flavor here — at the same time the demands that we all put on our horsepower and our people during the fleet shortages in 2022 were probably at levels that were just somewhat unsustainable long term. So with these two factors in mind, we shut down that fleet in East Texas. We dispersed this additional horsepower to fleets with our key core clients and we were able to maintain the same level of revenue and profitability that standalone fleet would normally make. So if you look at this we really see this as a win-win for both ourselves and our customers.

Derek Podhaizer: Got it. That’s very helpful. Maybe just going back it sounded like you signed an LOI just on the wellsite integration. Any more color you can provide on that? Is this a similar wellsite integration expansion that we saw with CIG Logistics you made the other year? Just anymore color around what type of opportunity this could be and the type of value proposition that you would be providing to your customers.

Robert Drummond: Yes. Look I think that you’re on the right track. I would just want to add a few comments. We’re committed to our capital allocation strategy and anything we’re looking at from an accretive M&A perspective has got to compete with our own buying back our own stock. We believe and we have been really Matt said the operation is really going strong from an efficiency perspective. But these opportunities to tack on a little technology and some integration — around our integration theme can take that to another level and that’s the logic for the deals. And we’ve been extremely patient throughout this process to get to the point where there was as opportunity to do that and find M&A deals that could compete with buying back our stock at a depressed level. Kenny, do you want to add anything?

Kenny Pucheu: Yes. Look Derek, I’ll just add we do have a non-binding LOI that we said in our call. We wanted to announce that fact just to make it public. And as we stated in our prepared remarks we plan to continue to execute on our shareholder return program. And I would just say at these levels probably aggressively.

Derek Podhaizer: Got it. Great. Appreciate the color, guys.

Kenny Pucheu: Thank you.

Operator: Next question comes from Jim Rollyson with Raymond James. Please go ahead.

Jim Rollyson: Good morning, guys.

Robert Drummond: Good morning, James.

Jim Rollyson: Robert just going back to one of the comments you made on the kind of opportunistic purchase of some of the electric pumps that you were going to filter into an existing fleet. Your prior to this your kind of strategy has been you’ve been working on the gas conversion stuff for a couple of years now. Obviously, you’ve talked about incrementally adding eFleets as the market and your fleet dictates. One of your competitors is kind of doing a similar thing with adding pumps kind of building up the fleet as it’s working. Curious how you view this as a go-forward opportunity to maybe replace some of the legacy pumps with electric pumps to kind of build up your eFleet side of things from active fleets.

Robert Drummond: Thanks, Jim. We appreciate the question. We’ve kind of been saying within our capital allocation strategy over time we’re going to move our fleet entirely to natural gas. A big component of that will be natural gas-powered electric fleets and being able to opportunistically find this opportunity to accelerate that to take care of some strong customer demand was something that fit in it. We have been measured about kind of talking about that previously but I think you can expect to see that from us over time. And I want to be careful to note very carefully that’s a balance some stuff going out and some coming in. Matt why don’t you add a little more color?

Matt Gillard: Yes. Okay. Thanks, Robert. So — I think Robert talked about the opportunity that we had that presented to us in Q1 to obtain some additional electric horsepower. And I think you mentioned Jim we’ve had electric horsepower dispersed within our diesel fleet for over two years now so we can see the value that it provides. One thing I’d like to say in addition to this is we already made a decision last year to actually invest in electrifying our blenders and ancillary equipment. These were at the heart of our diesel crews. So we made a very easy decision to deploy this additional electric horsepower that became available alongside our existing e-pumps married with the new electric blenders that we have in construction to generate the second Emerald crew fairly quickly.

By doing this, we were able to deploy the second Emerald fleet within our existing fleet transition CapEx. But at the same time, we’re lowering our maintenance CapEx by retiring further some of the Tier two pumps which have a higher cost to operate.

Jim Rollyson: Makes perfect sense. And then just one follow-up maybe for Kenny. Kenny you mentioned continuing to bring net leverage hopefully below zero by the end of the year. Is that strictly just going to be piling cash on the balance sheet, or do you think you will actually start paying off some of that term loan over and above the amortization rate?

Kenny Pucheu: Yes Jim, thanks for the question. I think at this point, I would say, it’s just strengthening the balance sheet with cash. But obviously, we’re watching whether that’s trading and if we see an opportunistic avenue to pay down some debt we would. But I would probably say we’re leaning towards cash right now.

Jim Rollyson: Great. Thank you, guys. Good quarter.

Operator: Our next question comes from Stephen Gengaro with Stifel. Please go ahead.

Stephen Gengaro: Thanks. Good morning everybody. Two things for me. One, we’ve heard a lot from you and your peers about price conversations or discussions. And just curious, when you’re talking to your customers right now, how much of the pricing discussion is around sort of the integrated well site opportunities? And how do you think about it sort of holistically from your view of sort of profitability per well site as opposed to sort of on a per pump basis? I’m just trying to get a sense for how we think about, how that sort of filters down into profitability per asset.

Robert Drummond: Look it’s a good question. When you look at profitability by unit or by fleet or by well site, no matter how you’re looking at it in frac, it’s a balance between pricing, contract terms, operating efficiency and integration. And we look at all those. And I think our customers appreciate that and there’s trade-offs less integration more price, higher efficiency less price to get to numbers that make our return thresholds. We’ve been very successful getting I would consider single-digit pricing increases in Q1 and I expect to see a little more pricing increase in Q2. And when I talk price increase, I’m talking about all four of those components. It is a holistic manner in which to look at it. And I think our customers more and more are open-minded about the integration aspect, because they’re looking at their bottom line and their returns, so anything that we can bring to the picture with bigger integration that addresses that is a good story.

It’s a support behind our M&A program and behind our support of using wet sand in the market and how wet sand is able to kind of drive down the customers’ overall costs, particularly when that mine location can be very close to where the operations are. Yes, I think these discussions include all of those things. And with the spot market volatility that was brought up earlier, I think we were talking about price with our customers. And I would say we’ve been guiding into the back half of the year that we’re still dealing with a lot of inflation. And if we can get continue to get price to offset inflation that we think we will then that probably will be what happens mostly in the back half of the year.

Stephen Gengaro: Great, thank you. And then just one quick one for Kenny. Is there — can you give us any framework for how to think about 2024 CapEx as a percentage of EBITDA? And I know you’ve talked a little bit about this in the past, but anything you can update us on there?

Kenny Pucheu: Sure. Look we’ve said very clearly in our capital allocation program that it’s through the cycle. And what I mean by that is we’re going to commit to 8% to 9% of revenue through time. 2024, you can anticipate the same thing.

Stephen Gengaro: Okay. Thank you.

Kenny Pucheu: Thank you.

Operator: Our next question comes from Scott Gruber with Citigroup. Please go ahead.

Scott Gruber: Good morning.

Robert Drummond: Good morning.

Scott Gruber: A question here on how market pricing could evolve. When the markets are super tight pricing spreads tend to compress across different pump types and certainly different operational efficiencies by company et cetera. But obviously, we could start to see some spread emerge here particularly between next-gen pumps and legacy pumps. Next-gen pumps obviously burning gas is quite a significant amount of fuel savings. I’m just wondering, if you look at the wide diesel gas spread today and you look at the fuel savings here for dual fuel versus running a diesel fleet, what magnitude of pricing spread would be supported by the wide diesel gas spread today?

Robert Drummond: Well, look the spread between price for any gas-powered unit versus diesel power is supported by that amount of displacement that occurs. And that’s a math equation about how wide is that arbitrage and the customers understand it very well and so do we. We price it to get as much of that as you can in your fleet and they offset it with the arbitrage. I think that that is a broad spread today and with diesel prices where they are and gas extremely low price in the marketplace that’s the reason we do a lot to try to facilitate keeping that arbitrage wide, because it supports the whole pricing structure for that bifurcation. And I think that bifurcation will continue to be a huge benefit. And the demand for those fleets is constant.

Anytime you have one you can just about deploy it. I think that’s not going to change perhaps maybe even gets better as we all get smarter about how to increase the displacement on these units. How you operate them makes a big difference. That’s another thing I think that supports bifurcation.

Scott Gruber: Definitely. Go ahead.

Robert Drummond: I was going to say did that address it, okay?

Scott Gruber: Yeah. I was just doing the back of the envelope math and getting to a fairly sizable number at $2 gas and $4 diesel, but I can run through it with you all offline. And just a quick follow-up, it sounds like you guys took advantage of a good opportunity to buy the eFrac pumps when they came to market from the OEM. But just curious why were they available? Was an order canceled by somebody else and with the OEM building some pumps on spec? How did those go into the market?

Robert Drummond: I think in this case, it was built on spec. And the thing that changed, I think was the contractual terms changed a little bit about maybe how you could access those pumps maybe not in a holistic system versus just individual pumps that made it a little more readily available. And that was it. I think there’s not a lot of — no inventory like that in the market today that, I know of but except for that. Back to your original question you asked me about — I’m sorry go ahead.

Scott Gruber: No I was just wondering about whether there’s additional opportunities like this or whether this was a one-off. It sounds like a one-off.

Robert Drummond: We think so.

Scott Gruber: Got you. Okay. Well, appreciate all the color. Thank you.

Robert Drummond: Thank you, Scott.

Operator: Our next question comes from Waqar Syed with ATB Capital Markets. Please go ahead.

Waqar Syed: Thanks for taking my question. I just wanted to understand a little bit more what you mean by the word moderate in your guidance for Q2. Given that your revenues in Q1 were up about 47% year-over-year the moderate growth or moderating growth could mean a number of different things. Do you mean that low to mid-single-digit type percentage increase quarter-over-quarter, or high single digits or more than that? Could you maybe provide some bookends there?

Kenny Pucheu: Hey, Waqar, good morning. Let me just reiterate what we said, because I think it is very important. Our outlook is essentially unchanged from our last update. We continue to see topline growth and we’ve called out 40% to 50% of adjusted EBITDA growth in 2023. I think that in Q1 we demonstrated that we are on that trajectory. And what I would just say in Q2 is that, we entered the quarter with momentum. We had a solid Q1 exit. We’ll have less weather disruptions in Q1. And we continue to see gains as we continue to push integration, which by the way we’re currently investing in heavily. And this will lead what we said as moderate Q2 topline growth and that’s all we’re really prepared to say at this point. But we also expect that this will lead to continued growth in our operating profits.

Robert Drummond: Improved free cash flow.

Waqar Mustafa Syed: Fair. Maybe if you could help us with the incremental kind of margins that you expect on this moderate revenue growth in Q2?

Kenny Pucheu: I’ve said, all we’re going to say at this time Waqar.

Waqar Mustafa Syed: All right. So thank you very much. That’s all I have.

Kenny Pucheu: Thanks Waqar.

Operator: Our next question comes from Kurt Haley with Benchmark. Please go ahead.

Kurt Haley: Hey guys. Thanks for squeezing me in really appreciate it.

Kenny Pucheu: Thank you, Kurt.

Kurt Haley: Yeah. For sure. So Robert, I’m — I kind of want to focus in on this transition dynamic that’s underway in the U.S. frac for you right? And in a lot of ways it kind of reminds me of what transpired in the U.S. land drilling market, I don’t know 10 or 15 years ago when the land rig dynamics shifted from mechanical rigs to AC rigs and there was a huge step change in drilling efficiency and etcetera, etceteras. right? It seems to me like the frac market is definitely on that path. So I guess my question really is, do you see — would you agree with kind of this analogy? And then if you did would you effectively suggest maybe that the electric frac fleets will become effectively the AC equivalent of the frac market? Or do you think that the dual fuel assets will still be the predominant asset in the marketplace?

You indicated a six to eight-year transition period so again let’s get out of the noise let’s get out of the stuff near term and maybe kind of would really like to get your thoughts on how you see it evolving.

Robert Drummond: Well, look, I think it’s a good point rigs versus the transition to natural guests for frac fleets. In both cases that investment is buying a return that’s very apparent. Rigs were buying increased drilling efficiency and our investment in these frac fleets is buying a return on the difference between oil and natural gas I mean diesel and natural gas price. I think that’s the logic. It’s an easy investment to make because the return is supported so much by that arbitrage. But when you look at where we’re headed I’d like to be careful to distinguish that I think we’re headed towards all-natural gas fueling. But I’m not so quick to say that it’s going to be all electric. Because, when you think about what’s happening, you have natural gas power generators or turbine-powered generators that use natural gas as well to provide electricity, to provide power to a pump.

And that’s not exactly perfectly efficient. And I would argue that, when you look at the math both from our perspective and the customers frankly the Tier four dual fuel systems operating properly supported by the likes of Power Solutions makes a very competitive stance. And maybe even some sort of hybrid in between. Somebody mentioned that some of our competitors I mean Arun mentioned that earlier doing some of that. So are we. I think that makes a lot of sense. But in any case the math on spend capital within the capital allocation programs that all of us have now in the sector it’s going to take a number of years to get there. And I think that technology will probably evolve a bit during that period seven eight years. And the endpoint may not look exactly like we think from the perspective of what exact kind of equipment is being deployed.

But certainly I believe using the lower-cost fuel system, cleaner fuel system makes sense on so many different levels.

Kurt Haley: That’s great. That’s great context and color. And my follow-up here is you’ve been very clear and very consistent as have others about capital discipline, pricing discipline and very clear that there’s a differentiation between what’s going on in spot markets versus dedicated fleets. But I can’t help but kind of think about prior cycle periods and there’s always this friction between E&P and service companies. And whenever E&Ps don’t see an opportunity, they’ll always try to kind of lean on the service guys to kind of give up on price even if it has been kind of a contractual or dedicated kind of arrangement. Just kind of curious as to beyond just the typical friction has there been anything else that’s been kind of bubbling up to the surface where there’s some incremental discussion going on where the E&Ps are trying to extract some price concessions? Anything that’s more the typical Robert?

Robert Drummond : No, I don’t think so. I mean they’re always going to want a lower price. We always want a higher price. I think that’s something that’s natural. The spot market disruption very predictable with a lot of fleets coming loose that were moving from gas to oil. But we believe we’ve got to trust the macro and make your business pricing decisions based upon supply and demand and utilization. I choked up a little bit during Arun’s question and didn’t really do a good job explaining. But at the end of the day I think that right now we’re sitting at like 98% utilization. And that’s less than last year when we were undersupplied substantially. And there are a number of fleets coming in but nobody has really given attrition the full look that it needs to.

And Matt and I talk about it all the time we’re running the fleet harder than it’s ever been run. I mean all of us. And that provides a lot of pressure on maintenance and with the supply chain the way it is I don’t think that it’s near the concern that’s being played out. I don’t blame the E&Ps for negotiating price a little bit through the market but at the end of the day, I think that all of us have taken a little bit more longer-term view in a capital-constrained market better than we ever have before. And that’s a new playbook.

Kurt Haley: Awesome. Really appreciate it. Thank you.

Robert Drummond : Thank you.

Operator: The next question comes from John Daniel with Daniel Energy Partners. Please go ahead.

John Daniel : Hi, gentlemen. Thanks for keeping the call going. Robert you guys have been very clear about the push for natural gas power fleets and the differentiation, which comes from just simplistically new versus old. Knowing this is it fair to assume that kind of going forward you guys are likely to pass on opportunities to buy the smaller frac companies who tend to be Tier two focused players?

Robert Drummond : Well, look we’ve said before that in the M&A arena of pure frac horsepower scale matters. And there are some cases where you might have a company that has a diesel fleet or a partial diesel fleet that scale could really make a difference and the payback on that could be relatively swift or swift to the point that it was better than buying our own stock back. I could see a case like that. Preferably any kind of M&A trade would be one that moved you on that curve towards a quicker conversion to natural gas. But I’d hate to say, we ruled it all the way out, but I think you’re reading the tea leaves pretty accurately there.

John Daniel: Yes never say never I get that. The customers adopting your electric fleets, do you sense they will go 100% electric? And if so I mean how do you I know you talked about six or seven years or so for the industry to make the transition but once that company customer decides to go how quickly do they speed the conversion, if that makes any sense?

Robert Drummond: Yes it does. I would just refer back to that question before in saying that the transition is going to take a long time. I’ve heard a few customers say they want to do that. But when you look at the time it takes and the amount of CapEx it takes for this fleet to get converted, that’s a multiyear deal. And if you take and added all those up that everybody wanted it probably is not going to be able to be done. And the second thing I’d say is that, by the time you get out there a little ways and you say look this Tier 4 dual fuel kind of arrangement displaces 75% or 80% sometimes of the gas and emission profile and everything else associated with that. You go maybe these hybrid fleets are better. So I’m not going to be surprised to see that happen.

And I’ve seen a few customers already kind of coming to that conclusion, which we thought would ultimately happen. There’s something sexy apparently about a pure electric fleet but I don’t know if that lasts forever.

John Daniel: Yes. Fair enough. Last one for me and this might – if I’m not mistaken, you guys still play in the cementing market. Can you give us an update on just trends in that business outlook? Any big picture thoughts would be appreciated.

Robert Drummond: Yes. Look, I’d just say that obviously, it’s tied to drilling rig count a lot and what they have to offer. We’ve had our particular piece of the business, we have shrunk our footprint to be where we wanted to be a while back, focusing on getting our efficiency and our loading and our returns where they needed to be. And we’ve done that. Kenny talked about the results a little bit. And we like that business. It’s one that is generating free cash flow and we like it. And I just think though it’s married a bit to what happens in rig count. And by the way I would argue earlier when I was choked up that drilling rig count in oil dropped a little bit. And I think the oil price now is back up and I wouldn’t be surprised in the back half of the year if the oil rigs kind of recover back to where they were in the first quarter. Up a little bit beyond that even. And I know a few drilling contractors who have a similar view to that that I have.

John Daniel: Okay. All right, guys. Thanks for including me guys.

Robert Drummond: I appreciate it.

Operator: Ladies and gentlemen we have reached the end of the question-and-answer session. I would like to turn the call back to Mr. Robert Drummond for any closing remarks.

Robert Drummond: Thank you very much for participating in today’s call and for your interest in our company. And I’m extremely proud of our team’s execution through recent commodity volatility and we’re going to continue to show our customers the value of our NexTier partnership and we will continue to look for ways to help our customers maximize their returns while also maximizing our own. Thank you again.

Operator: The conference has concluded. Thank you for attending today’s presentation. You may now disconnect.