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spk07: Good morning and welcome to the next year Oilfield Solutions fourth quarter 2022 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 introduction, I would like to turn the call over to Mike Sabella, Vice President of Investor Relations for NextTier. Please go ahead.
spk06: Thank you, Operator. Good morning, and welcome to the NextTier Oilfield Solutions Earnings Conference call to discuss our fourth quarter 2022 results. With me today are Robert Drummond, President and Chief Executive Officer, Kenny Pichu, Chief Financial 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 update publicly any forward-looking statements except as they may be required under applicable securities laws. We refer you to next year's 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 to the most directly comparable GAAP financial measures are included in our earnings release for the fourth quarter of 2022, which is posted on our website. With that, I will turn the call over to Robert Drummond, Chief Executive Officer of NextYear.
spk05: Robert Drummond Thank you, Mike, and thanks to everyone for joining the call today. 2022 was a strong year for NextYear. While we will not rest on our past successes, I do want to take a moment to reflect. We started 2022 by asserting our view that the frack market was tight and that frack equipment would become harder to find, a view that was far from the consensus at the time. Indeed, frack quickly emerged as one of the main bottlenecks in the U.S. shale oil and gas market. Against this macro backdrop with strong demand and limited supply for our services, Our pricing outlook improved considerably as the year progressed. Importantly, we were able to deliver strong results for our investors while also delivering best-in-class service for our customers. To all our hardworking employees and their families that made last year possible, thank you for contributing to the success of our company. I could not be prouder of what we accomplished together. At NextYear, we are committed to sharing in the success and investing in our people as we strive to make this a destination for the hardworking men and women of our industry who are looking to build a long and prosperous career. During 2022, our success extended beyond just the core frack operation to each of our service lines with profitable growth in wireline, cement, power solutions, and last-mile logistics. But despite the progress we made last year, our business still has not returned to pre-COVID net pricing, and we are still looking to recoup prior investments we made to improve efficiency. Our prior investments must be combined with supportive fundamentals if our industry can be expected to drive the next leg of process improvement and fully reflect the value we can create for our customers. On the macro front, we believe the cycle has only just begun with a setup in 2023 that is as good as what we saw in 2022. We believe demand for frack fleets today exceeds supply by 20 to 25 fleets with as much as 10% of horsepower demand going unmet, which has allowed us to raise price this year already. We also have customers that are inquiring about 2024 work now. But fully satisfying demand of our customers has its challenges. Our supply chain remains stretched with a backlog for parts that is substantially higher than normal. We've seen little progress so far in correcting the situation, but while some argue that current economics will stall attrition, the reality is that supply chain challenges, capital discipline, and inflation are more likely to cause attrition to accelerate and new builds to delay further. In fact, delivery of our own electric fleet has been delayed in the Q2. At next year alone, we plan to decommission roughly 150,000 horsepower over the next 18 months, meaning within our capital budget framework of 8% to 9% of revenue, our capacity will remain relatively flat this year. We will continue to allocate capital to the highest return investment. And as we show on slide 11 of our updated investor presentation, investing in these older assets no longer meets our hurdle rate. It makes more sense for us to invest in new equipment than to continue to deploy capital into these older obsolete assets. We do not believe we are alone in this attrition narrative. Even with the new bills, we see a challenge path to increasing industry frack capacity, which should lengthen the cycle and solidify another round of price increases. At the same time, and as we show on slide 12, a bifurcated industry fleet with a steep equipment cost curve is allowing our natural gas-fueled assets to earn a premium return. These differentiated returns, supported by the fuel cost arbitrage, should last several years as the industry fully transitions to next generation equipment, a process that will likely take over seven years at the current new build cadence, with more than half of industry capacity still legacy diesel fleets. The demand side is supported by what we see as an underinvested oil and gas market that needs to increase production to avert a global energy supply crisis. U.S. shale's role will no doubt be critical in balancing global commodity markets, but our customers are restricted by their own capital discipline, as well as the availability of equipment like frac. We do not believe shale is prepared to quickly answer the global call, which should lengthen the demand cycle for our services as the world searches for more oil and gas. For our next tier, We believe we're on a path to additional profitability in 2023 and beyond. We entered this year still roughly 10% below pre-COVID net pricing for our frac services, and we will look to recapture that throughout the coming year, some of which we've already realized. We also see opportunities to grow our well site integration offerings and invest in high return projects that support efficiency in our core frac operations. Even as the strong macro environment plays out, we will continue to lead our industry in disciplined behavior and use our returns to reward our shareholders. We've established a track record of delivering strong free cash flow, high return on investment, and capital efficient growth. We will continue to focus on maximizing returns on capital and returning capital to shareholders. We believe this will be the winning strategy for our company and our investors. While our industry fundamentals remain strong, we would be remiss to ignore the growing dialogue around weakness in the near-term natural gas fundamentals. For next year, our largest natural gas exposure remains in the Marcellus. Takeaway capacity has constrained activity in that basin for some time now, and activity there has been relatively steady over the past couple of years compared to other gas basins. Coupled with the lower break-even well economics, we expect Marcellus activity to remain relatively steady despite the drop in natural gas prices. Because of this, we think that Haynesville will take the brunt of any activity decline. History suggests worst case is perhaps a 50% decline in Haynesville activity which would imply as many as 14 frac fleets could be released from that basin, a scenario that would result in a significant decline in basin production. But we want to be crystal clear. We fully believe the fundamental undersupplied nature of the frac market in the oil basins could easily absorb these fleets. Even in this scenario, when taking into consideration current unmet demand, modest demand growth in oil basins, and the planned frack fleet additions, we believe total utilization is likely to remain balanced. Even a small amount of attrition would keep the industry fully sold out through 2023, and we believe attrition is inevitable, as evidenced by our own actions. Our macro view has always taken a more conservative view on near-term recount additions due to our understanding that frack fleets are the bottleneck to production growth. So while we are watching the natural gas fundamentals just like everyone else, we view the potential disruption as a relatively minor threat, given our view that the overall U.S. land frack market is still undersupplied and likely will be throughout 2023. It is important to note that we only have a small exposure to the Haynesville with just two fleets operating in that basin today. Additionally, we're not hearing any commentary from our natural gas customers about slowing the pace of completions. Further, low gas prices increase the cost advantage of our natural gas fuel fleets, which could solidify demand for those premium assets and raise the value of our power solutions business. Nevertheless, even as we see the cycle continuing, we are nimble, and can respond quickly to unforeseen changes. We have a sticky customer relationships and we will always prioritize a strong balance sheet with substantial liquidity. Now to our results. We saw improved profitability and returns sequentially, even in a counter seasonal period. Net income of $133 million improved 27% from the prior quarter and was 15% of revenue. Our net income per diluted share was 52 cents. Total revenue of $871 million was down 3% sequentially, but was 71% higher than the same quarter last year. Our adjusted EBITDA was $213 million, was up 9% from Q3. We effectively managed our decremental margins on a sequential basis and we managed to shift to higher margin work with better returns. We also continued to generate very strong free cash flow, generating $93 million in Q4, even as we funded an Alamo earn-out payment. During Q4, we repurchased 11.5 million shares for $113 million under our $250 million shareholder return program, funded entirely with free cash flow and cash on hand. For the full year 2022, we more than doubled our revenue, with adjusted EBITDA nearly six times greater. Most importantly, we achieved this strong growth while staying very disciplined with our capital allocation and generating $295 million in free cash flow. Since the very start of the recovery, we saw that winning this cycle was going to require a different approach compared to prior cycles. We've been steadfast in our message that our goal is to balance future growth needs demanded by our customers with returns and free cash flow needs demanded by our investors. We're happy to see this strategy being repeated by many of our peers across the industry. Capital discipline has become a common theme in the industry. which should lengthen the duration of the cycle. We're proud of our success in balancing these two strategies, and we have high conviction that this is the best path forward for our company and our investors. As you see on slide 15, we've achieved our growth in a very capital-efficient manner. On slide 16, we show that we achieved our growth over the past year while deploying significantly less capital relative to our peers. For 2022, our 30% return on invested capital has improved significantly over the past year. In the fourth quarter, we delivered an annualized ROIC of 46%. ROIC is one of our highest priorities we consider whenever we make an investment decision. Maximizing returns requires smart and opportunistic capital allocation. We invested countercyclically, which allowed us to create additional value during the early parts of the cycle, and we continued to rationalize our asset base. We sold $50 million of non-core assets last year and redirected the funds to areas where we could create better value for our shareholders. We believe our return should improve significantly again in 2023, and have the potential to stay high for multiple years. We expect strong demand will continue, and on the supply side, the market remains undersupplied and consolidated. Additionally, growing capital discipline in our industry and equipment and parts availability are restricting our ability to add and maintain equipment. Finally, bifurcation and equipment quality is elevating in returns as the industry undergoes a lengthy conversion to natural gas. During 2022, we reported earnings per diluted share of $1.26. Our share price today is just seven times our 2022 earnings per share, and considering we expect EPS growth again in 2023, we believe our forward-looking price-to-earnings ratio is even lower We generated $295 million of free cash flow in 2022, and our expectation is that we will increase our cash flow to at least $500 million in 2023. We see free cash flow conversion over 50% this year, and we still see a path to growing our adjusted EBITDA 40 to 50% relative to 2022. Ultimately, The goal of this strategy is to maximize value creation for our shareholders. Last quarter, we presented a detailed capital allocation strategy that rests on two foundational pillars. We will prioritize a net debt zero capital structure to ensure our business remains nimble through the cycle. And we will look to invest 8% to 9% of our revenue in CapEx annually which we believe is sufficient for us to maintain service quality and market share in our core product business while slowly transitioning the rest of the fleet to natural gas powered and funding growth in our well site integration strategy. On top of this foundation sits what we believe is a durable free cash flow profile. We will return at least half of this free cash flow to shareholders through a process that we started and 2022. Through February the 14th and including the amount we used in Q4, we've repurchased 14.4 million shares for $139 million, bringing the total to nearly 6% of the shares that were outstanding prior to the buyback. After funding our shareholder return commitment and reaching our capital structure goal, We believe that we have optionality on roughly $200 million in cash through the end of this year. We remain interested in M&A, including both for further consolidation of the frac market, as well as other avenues to grow our successful well site integration platform. We have a very strong M&A track record as been demonstrated by our recent acquisitions of Alamo and CIG Logistics, both of which easily outperformed initial expectations and have become core to our company. But we will continue to be prudent and we'll act on transactions that make sense for our shareholders. 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. We remain committed to maximizing the value of every dollar of capital in all phases of market cycles, guided by our sustainable capital allocation program. We believe the significant use of cash to repurchase shares should demonstrate our dedication to our strategy, as well as our conviction in the long-term outlook for our business and the belief that our equity is significantly undervalued. The prior cycle OFS playbook, which was guided almost solely by EBITDA growth and relied on indefinitely capitalizing one-year returns in new-build economics, while ignoring industry supply and demand fundamentals did not work. We believe our balanced strategy better served the company and our shareholders and we will continue to chart this new course. We have strong conviction that capital discipline and a focus on sustained returns and capital efficient growth will be the winning formula in this cycle. We are bullish that the cycle is in its early stage We are prepared to deliver strong value creation and return capital to our shareholders the entire time. I'll now pass the call over to Kenny to discuss the fourth quarter results in more detail.
spk01: Thanks, Robert. Fourth quarter revenue totaled $871 million compared to $896 million in the third quarter. Revenue decreased 3% sequentially, which was in line with our guide. We had strong execution and pricing continued to strengthen during the quarter. which was offset by seasonal downtime, as well as lower product sales. We continue to operate very efficiently with near company record pumping hours per fleet on average, even with seasonal disruptions. Revenue declined in our completion segment, while the well construction and intervention services segment revenue improved on strong demand and solid operational performance. Total fourth quarter adjusted EBITDA was $213 million, an improvement from $195 million last quarter. We increased profitability despite lower revenue based upon several factors. First, we saw a shift in work to higher efficiency, higher margin jobs during the quarter. This lower revenue, more profitable work is a function of aligning ourselves with like-minded customers that focus on efficiency, integration, and value creation. This realignment is also serving us well in 2023. Second, while holiday downtime was a factor in our results, we managed costs to help minimize the impact on our profitability. And third, the investments we are making to improve our efficiency and cost structure are working. These investments, such as expanding the functions of our next hub digital center, upgrading ancillary equipment around our faculty, and improving last mile efficiency, go straight to the bottom line and were critical in the quarter-on-quarter improvement. In our completion services segment, fourth quarter revenue totaled $830 million, compared to $858 million in the third quarter, a sequential decrease of approximately 3%. Completion services segment gross profit improved to $227 million, even on lower revenue, as we upgraded the quality of work and effectively managed costs. In our well construction and intervention services segment, fourth quarter revenue totaled $41 million, an increase of 7% compared to $38 million in the third quarter. Gross profit totaled $10 million, an increase from $8 million in the third quarter as our cement operations showed strong improvement. Fourth quarter selling, general, and administrative expense totaled $37 million, flat compared to the third quarter, and excluding management net adjustments of $7 million, adjusted SG&A expense totaled $30 million. EBITDA for the fourth quarter was $200 million. When excluding management net adjustments of $13 million, adjusted EBITDA for the fourth quarter was $213 million. Management adjustments include $7 million in stock comp, with other items totaling a net of $6 million, which are non-recurring in nature. approximately $6 million of total net management adjustments were cash-related. Now on the balance sheet, we exited the fourth quarter with $218 million in cash, down from $250 million at the end of the third quarter. We exited the fourth quarter with total available liquidity of approximately $634 million. Our liquidity was comprised of cash of $218 million and $450 million available on our asset-based credit facility, which remains undrawn. Total debt at the end of the fourth quarter was $361 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 fourth quarter was approximately $143 million, an increase from $150 million at the end of the third quarter. This sequential increase in net debt is a function of the use of cash as part of the share or purchase program. Cash flow from operating activities was $144 million for the quarter. Profitability strengthened, while the sequential decline is a function of the Alamo earn-out payment during the quarter. We continue to aggressively manage our working capital and saw solid improvements in our cash collections. Our cash used in investing activities was $51 million during the fourth quarter, and CapEx totaled $79 million, mostly driven by normal maintenance, investments in the next phase of our power solutions growth, and proactive investments to increase our inventory of spare major components, such as engines and transmissions, as we looked to minimize the impact of the tight supply chain. We also funded the replacement pumps for the portion of the fleet we lost to a fire in Q3, which was entirely offset by insurance proceeds. This resulted in overall positive free cash flow of $93 million for the fourth quarter. Now on the outlook. Customer demand was very strong as we entered 2023, and this has continued through Q1. We had a very encouraging start to the new year with very little impact for normal startup issues that can arise after the holiday slowdown. As is always the case, winter weather will have an impact on our Q1. For the first quarter, we expect total revenue will be up at least 6% sequentially. Consistent with previous guidance, our 2023 CAPEX budget remains at $350 million, which, including attrition, will result in relatively flat horsepower deployment through the year. We 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. We see free cash flow of at least $500 million in 2023. We are excited about the company we have built. We've made smart capital allocation decisions that have positioned us to outperform our peer groups on returns, free cash flow early in the cycle. We plan to continue to win through our focus on balancing high return investments and dedication to capital discipline. As we pointed out in our updated investor presentation, the oilfield services sector is healthy. Returns at most of our peer group are exceeding the cost of capital for the first time in many years, and the sector is generating meaningful operating margins. Contrary to prior cycles, the industry is prioritizing shareholder returns, which should mean a longer or durable return profile for next year in our peers, and thus, a more investable industry. We believe current equity valuations are not indicative of our sustainable earnings profile. We see no indication of a slowdown with macro fundamentals expected to remain strong for multiple years. I'll now turn it back to Robert for closing remarks.
spk05: Thanks, Kenny. As we announced earlier this week, we recently added an independent director. Leslie Beyer has agreed to join our team and will be an important voice for the company as we enter the next phase of our development. Leslie is the CEO of the Energy Workforce and Technology Council, the largest energy technology and services association in the world. She brings with her a wealth of oil and gas knowledge and expertise, and we're so delighted to have her voice in our boardroom. Now let me close with a few takeaways. First, we're very excited for 2023. Industry fundamentals are as strong as they were last year, and the tightness now is far better understood. Given the sold-out nature of the frat market, customers are actively looking to align themselves with the most reliable partners as they look to maximize their own capital efficiency. Several of our customers are already starting conversations now for 2024 work. Our operational excellence puts us high on that list. We have repositioned our footprint commercially and geographically to align with strong partners, which should mean higher profits in 2023. Second, our well site integration strategy is a differentiator that relies heavily on value creation and synergies. For next year, our integrated offering either lowers the total cost to operate a completions well site or raises efficiency, and in most cases, both. This value creation allows us to earn strong returns while also offering the customer a superior product. If we do not see a path to process improvement, we do not see the need to invest our capital dollars in the service. Finally, we still see some investors and analysts discussing the investment strategy for OFS in the same context as prior more growth-oriented cycles. The industry's changed. Durable returns, earnings per share, and free cash flow are increasing in importance and must be considered alongside EBITDA growth. We see this as the best strategy to attract the next generation of investors back to oilfield services. And next year, we're doing our part to lead the industry into this next phase. With that, we'd now like to open the lines for Q&A.
spk07: Thank you, and we will now begin the question and answer session. To ask a question, you may press star, then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. At this time, we will pause for a moment to assemble our roster. Our first question today is going to come from Scott Gruber of Citigroup. Please go ahead.
spk11: Good morning. Great execution this quarter.
spk03: Thank you, Scott. Thanks, Scott. Good morning.
spk11: I think I want to start on your comments regarding the unmet demand in the oily basins. Obviously, as you mentioned, the market's concerned about gas-directed activity migrating out into the oily basins. So just some comment on how you dimension the magnitude of that unmet oil demand. You're looking at stuff counts, is it based on customer conversations, a blend of the two? Just some color on how you arrived at the 20 to 25.
spk05: I'd be glad to walk you through that. If you go back to Q3, we were saying then that frack demand growth was higher than frack supply growth and that frack supply was already at that point the bottleneck for U.S. production growth. And a little bit contrary to the pack at that particular time, that the current rig count was increasing the duck count, you know, even back then. You combine that with the fact that the frack supply chain is stressed and that attrition for the frack fleet is very real. And that's kind of the backdrop for it. But certainly any kind of projection that you put on you know, macro supply and demand has to be built around what is the macro for oil and gas. And for oil, you know, I think the near-term narratives are around recession and inflation impact, China, you know, Russia, the U.S. land natural gas price, and also maybe the SPR replacement, balanced against the structural long-term undersupply scenario. So we're not going to try to predict the oil price, but and we look at what our customers are budgeting, and we look at our view of the long-term kind of runway for oil, it's very supportive. So then you kind of take and drop that into, you know, frack supply and demand. We exited last year, you know, with about 272 fleets operating, we thought, in a market that needed about 20 to 25 more fleets. And that, you know, is the beginning of taking a look at what you would project it to look like at the end of 23. So there's been a lot of discussion about drilling rig additions in 23. That number's continuously came down over the last few months, and we've been very conservative about that because we always knew that, you know, frack was more or less the bottleneck. So we just take a slight increase in drilling rig count, and the oil basins for next year generates you know, a demand for about 10 more frack fleets. And then we take a look at the Haynesville side of the scenario, and there's been a lot of discussion, and we mentioned in our prepared remarks that, you know, we see that there's going to be some activity decline, we believe, even though the customers are not saying it yet. We believe there's going to be some decline in the Haynesville more than any other gas basin. So we went back and looked historically, you know, the last two down cycles back in, 2016 and 2020 gas price around $2. We saw a 50% reduction in the frack fleets in the Haynesville. That's about $14. It's not dramatic to the macro, but you've got a few additional oil rigs on the demand side and a few less gas rigs. Take a look at the supply side. We've spent a lot of effort. to stay on top of what we believe is about 29 new builds and reactivations that are coming into the market. You know, in 23 throughout the year, a significant number of those hit in Q1 as it was projected. But there's a lot of pressure pushing those to the right as well. I mentioned in our fair marks, in fact, our electric fleet is getting pushed into Q2. But if you just put any kind of conservative attrition number on that side of the the supply side, even, you know, as little as 5%, which we think is much more than that, but just say 5%, that projects into a balanced market as you exit 2023. So we like the way that shapes up. And, you know, some of that stems around if you believe duck count's been increasing or not. And, you know, the EIA recently kind of came out with their last three numbers for November, December, and January. And, you know, they were up. 14, 35, and 42 ducks, you know, per month. Our own numbers are a little bit higher than that, and we believe that even in February we're going to see the duck count in the U.S. on a macro increase by, you know, between 40 and 50. So I'm glad you asked that question. I really wanted to be able to address what we've been hearing, you know, kind of in the press a little bit about a second half pressure. You know, we just don't see it that way, and that's the reason. That's as detailed, you know, as God as I can probably get to.
spk11: No, I appreciate all that detail. And I do want to turn to the power solutions business, which is, you know, appears set to offer a lot of value to clients, you know, in the current market, you know, with this widening gas diesel spread. You know, what are you hearing, you know, from your clients on incremental demand, you know, for your power solutions business? offering and, you know, is it something that you're contemplating, you know, increasing spending on this year, you know, shifting some of the budget more that way? Just kind of some of the latest conversations on, you know, your expansion in that business and customer appetite for more.
spk05: Yeah, I'll start in the back end of that. Thanks for asking. You know, Power Solutions has been something we've been very proud of. We built that business to fuel ourself. and help us get the maximum displacement of diesel with CNG for our own frack fleets in the beginning. And as far as how much growth we'll have, I think the exit of 22 versus the exit of 23 will be more than double. And it's a very robust business that we've been able to keep sold out ahead of delivery, and we're making a notch up in Q1 on deployed fleets, substantial notch up. and then again in the back half of the year. So we're continuing the investment into that high-return business. But that business is very valuable to us, not only in the sense of the P&L associated with the CNG fueling business, but also the efficiencies it adds to the overall frack franchise. Where we have power solutions combined in an integrated model on location, our frack fleet's dual-fuel system Diesel-fracked combination fleets displace natural gas at a much higher rate than the average in the market has been told to us by our customers. So, yeah, it helps us capture the fuel arbitrage to a greater extent, adding returns to our fracked fleet as well as its own P&L. So it's been a thing that we're going to continue to go. And we even... would say openly that we'd like to keep looking inorganically around that kind of model to continue to grow that business with a robust cash flow we have.
spk10: I appreciate that call, Robert. I'll turn it back. Thank you. Thank you.
spk07: Our next question today will come from Stephen Gingaro with Stiefel. Please go ahead.
spk04: Thanks. Good morning, everybody. Good morning. Two things for me. One, I guess follow up on Scott's question. When you guys laid out in your analyst day the $7 million of cash savings per fleet, I think it's five of you, but two of cash flow, where do you stand on that initiative? How much of that is flowing through this pretty healthy annualized EBITDA per fleet number right now? And how much do we think about maybe being additive over the next 12 months?
spk05: You know, we can only move as fast with that comprehensively as we can grow the capacity of power solutions. But we've got plenty of capacity in wild line and plenty of capacity in our last mile logistics. So each one of the components of the integration are on a different run rate, I'd say. But we continue to move it up slightly. I was saying last quarter, you know, we were probably in the third inning, something like that, or Some fleets were 100% and some were, you know, at 10% or something. And that's something that as we moved from 2022, made the decisions about who we were going to partner with in 2023 that we took into consideration. We moved as many, you know, over 25% of our customer base changed between December and January in tune with that. Sometimes you take a step forward with integration and sometimes you just take a step backward. But in the cases where we actually took a step backward from an integration standpoint, we took a position that gave us better returns overall. And then we can turn around and build on the integrations as we get deeper into the year because we found once we get a toehold, typically it doesn't take very long to begin to demonstrate the value of the integrated model and we're able to build upon it. So I'd still say very early days, but we expect to make a lot of progress on that in 2023. In fact, we're in the process of a slight organizational tweak to enable the management in the field to be able to better align and drive that process. So I'm excited about the upside potential of it.
spk04: Great. Thank you. And then my follow-up is probably two parts, but one is when you think about the first quarter, Can you just give us your expected fleet count, and based on your revenue growth, it feels like there should be 15 or 20 million of incremental EBITDA growth at reasonable incrementals. Is that in the ballpark of where you're thinking?
spk05: Yeah, let me just kind of take into account how things kind of flow a bit. More and more, we're getting, you know, it's harder for us, I'd say, to talk about fleet allocations when we're really thinking about more horsepower allocations You're going to see a lot, I think, or some drift in our fleet count up and down going forward, I'd say forever, as we configure our fleet optimally, fleet to fleet, geography to geography, client to client. Even though our horsepower, I expect to maintain flat. So, you know, that's one thing I'd say. And then I would also say, as we went into Q1, I don't think I can say that I've ever been more pleased with the start we've had to a quarter. You know, I talked about the turnover we had in customer base. That began in December. It created a situation. We had the best month we probably ever had in January. And that's usually not easy to pull off. So, you know, February you got, you know, a little bit of freezing weather days that hurt us in the Permian, but we're off to a great start there. So,
spk01: And even with the weather impacts built in early Feb, we do see that top line growth of at least 6% that we said. And I want to be clear, we're expecting to grow profitability quarter on quarter. Whenever you look at that revenue growth, there's going to be some positive impacts on pricing and operational performance and calendar improvements. And this is going to be partially offset by weather. We think that February actually cost us probably about $25 to $30 million on the top line. But still, again, in that 6%. But with that being said, we expect probability to continue to increase at a good pace, quarter-on-quarter. And even with that February impact, we're excited about continuing to improve that.
spk05: And to the point about the fleet count, I just said we originally had said we'd have a fleet starting in Q1, the electric fleet, but I would say that I would move that into Q2.
spk04: Okay, great. Thank you both.
spk03: Thank you.
spk07: Our next question will come from Luke Lemoine of Piper Sandler. Please go ahead.
spk08: Hey, good morning, Robert, Kenny, Mike. Hey, Luke. Robert, I guess with the pace of your buyback, it almost seems like you're not going to leave any stock for anyone else to purchase. You just chewed through over half your authorization within four months. I guess if we look at your free cash flow for this year and the pace of your buyback, it seems like this authorization could be finished in the next several months and maybe a possible authorization increase. I totally realize an increase in authorization is a board decision, but it would be helpful if you could maybe just comment on the pace of the buyback along with maybe your possible willingness to return well over 50% of free cash flow to investors in a year if you continue to see the stock undervalued.
spk05: Yeah, look, I would start by, thank you for the question, start by saying that, you know, stay into the 50% return of free cash flows solidly in the plan. You know, I would look at it like the commitment for the $250 million return for 2023, I would look at it just as we got started early. The sale price on the stock was just too attractive and we went aggressively for it. I think that when we look at re-upping it, I think that it will be in the context of that 50% of free cash flow and perhaps looking at it from maybe getting an early start on 2024. But no announcement now about any change to it other than that we're, you know, on the same path that we've got to do what we're going to be on. But I wouldn't be surprised to see that evolve as we get into the next quarter.
spk01: Yeah, and I'd just add, you know, keep in mind we're balancing all the elements of our cap allocation program. We're going to have capex that will be somewhat front-end loaded as we invest early. On the buyback, you know, we have a very aggressive start. You'll probably see some of that activity subside some. But what I would say is that, you know, at these pricing levels, we're going to continue to be opportunistic.
spk03: Okay, got it. Thanks a bunch. Thanks, Luke.
spk07: Our next question will come from Derek Podhaser of Barclays. Please go ahead.
spk12: Hey, good morning, guys. I wanted to go back to the attrition conversation. Just maybe expand on the different components that you're seeing. I mean, there's definitely many forms to what attrition is. We've been seeing your deployed fleet count come down a few over the last couple quarters. You're talking about 29 fleets coming into the market. You mentioned 150 horsepower be decommissioned. Maybe just talk about, will you be replacing that 150? How are the extending maintenance lead times acting accordingly? Just maybe the different pieces that you could talk about to why the 29 coming in shouldn't spook or scare any investors because you'd expect some coming out through all the different forms that we're seeing.
spk05: Yeah, Derek, thank you for the question. You know, we tried to anticipate that more and more after hearing the dialogue in the market. You know, the investor deck that we put out last night, I would refer people, I thought this was the best view of it I've seen before, on deck page number 11, where it shows the rebuild cost versus new build cost and how the salvage value for the old diesel fleet declines each time that you rebuild it, and thereby you reach a point where the return on investment of a new build is better than the return on investment for a refurb. And I think that a large portion of the diesel fleet that's out there in the market, not just ours, but others, are in that kind of category. So you go to the point that you got 29 announced, kind of, we believe, kind of following 23, you know, new E-fleets, direct drive, and, you know, rebuilds in the markets. that that's about as much as it could be. And then you go and you think about the attrition side, supported by what I just said is that even if only, you know, 3% of the fleet attrits, you know, that's saying that the frack fleet lasts 30 years. You know, a frack fleet just doesn't last that long. So I think when we talk about our horsepower being flat, we talked about having an electric fleet coming in, and the fact that we're going to retire 150,000 horsepower over the next 18 months, all of that kind of leads to us saying that we're going to keep the same amount of supply in the market through 2023 and that we're going to manage it. And it's not that we're being stupid and cutting up equipment. It's because there's a better return to do so by replacing it with a new build, in our case, electric. So that's the logic that I think applies across the whole fleet. And honestly, I honestly believe that that's not even a choice. The supply chain, the way it is right now, we're struggling to keep up with the parts needed to continue to do maintenance cap tax. So I think that's also systemic across the entire sector.
spk12: I appreciate the comments. And just quickly to follow up, that 150 you plan to replace all that, would that be with all electric pumps, or do you expect to acquire or purchase any more Tier 4 DGB pumps on that 150?
spk05: That's mostly going to be electric, but I would say opportunistic opportunity to pick up these Tier 4 dual-fuel fleets that we've – the decision we made to make that investment. The more and more I think about it, the more I like it. It's got a great return profile, and it's maybe better than electric in the long run. The fact that we've been kind of going slow on deploying electric has been in our favor, I think. There's things about the market and how that's powered that it's getting better all the time, and I feel like the return on these Tier 4 dual fuels is going to be good for a long time. So we might sprinkle a little bit of that in there with it.
spk01: In fact, we still have roughly about two fleets of Tier 4 that we need to convert to Tier 4 DGB that just slipped from last year due to the supply chain. So in our CapEx budget, we already have two more fleets coming in.
spk05: But the main thing is you really got to be gas-powered to take advantage of that fuel arbitrage, which is a big number.
spk12: Right. No. Okay. That's helpful. And then for my follow-up, just want to go back to M&A. You talked and stick on the consolidated on the frack side. What would that look like for you guys? I mean, I think a lot of these privates have been taken up. There's not too many out there with real next generation pumps. It's more of the tier two diesel stuff that's been taken up off the auction blocks. We've seen one of your larger peers take out one or two of those. What is consolidation on the frack side look for you? What are you looking for Is it just taking those pumps out of the market? Do they have maybe vertical integration aspects or facilities that are attractive to you? Just some more color on that would be helpful as far as M&A targets.
spk05: Yeah, I guess you recognize that's a slight change in what we've been saying, and it's meant to be because of the big factor that I just mentioned a bit. I think the smaller your company is, the more challenging it is to tap into an already difficult supply chain. So some of the deals that perhaps could be available could have such a good return profile that you can't ignore it if it came down to a small company that was unable to keep the fleet in the condition in which they wanted to because of lack of access to parts. So if it was a very quick payback, consolidating traditional equipment I arguably would have been ruling that out six months ago that I would have maybe considered today. And the second thing I would say, any company that is in the line of the transition from diesel to gas that would help in a combined manner would be a logical M&A in the frack arena directly.
spk12: Very helpful. Appreciate it, guys.
spk03: I'll turn it back. Thanks, Derek.
spk07: Our next question today is from Kurt Halid of Benchmark. Please go ahead.
spk03: Hey, good morning. Good morning, Kurt.
spk02: Hey, great color today. Really appreciate it. So I'm curious, first and foremost, you talk about supply chain and lead times being extended. You kind of referenced that on the third quarter conference call as well. So what are the particular parts or pieces of equipment where you're seeing those lead times increase? and are you seeing them extend relative to what they were in the third quarter or, you know, have those lead times kind of stabilized at this point?
spk05: It's hard for me to be overly specific without maybe hurting myself, and I don't want to do that. I would just say is that relative to Q3 that it's about the same, and I would have hoped it would have been a little bit better. And I would say that think about it being the big components mostly. And I would also say that there's spots where we've made some progress, but there's spots where we haven't. I'm talking about the big we, all of us, in my view. And I think that there is signs of... of ability to make a difference. But some of that is in your own control, and some of it, you know, you have to be in a partnership with one of your vendors. So we spend a lot of time now trying to make sure the interface between us and our vendors is as good as it could be, just like we do the interface between us and our own customers.
spk01: And I just add that, you know, we've been investing in CapEx and inventory just to kind of take control of our own destiny in that space. to make sure that we can supply the fleet, probably carry more inventory and capex than we would have in the past.
spk05: And align ourselves with the vendors and helping them to whatever their goals are, we are trying to help them, you know, if it's better visibility on planning or if it's front-end payments like Kenny's talking about.
spk02: Okay, got it. So my follow-up would be, you know, you mentioned that you have strong conviction in your ability to kind of recapture the lost pricing that occurred during the COVID period, right? So I'm really just kind of curious on your perspective, right? We have a situation that, you know, could evolve, as you mentioned, where you could see 50% of frack activity decline in the Hainesville, not saying that you're predicting that, just saying that that's what happened last cycle, right? And you've got, let's say, those 14 fleets going and trying to find a home in the Permian or another oil basin. That typically creates kind of asset-on-asset competition and kind of puts the negotiating leverage back in the E&P hands, right? So, you know, just kind of curious, you know, what kind of underpins your conviction or has your conviction changed at all about kind of recapturing that pricing given what's going on in the natural gas markets right now?
spk05: Look, that goes back to the supply and demand balance in FRAC. Either you believe it or you don't. And you think about this time last year, how the dialogue was, what we were saying versus what was being said by, you know, many of the EMPs that they didn't realize yet the supply and demand balance was what it was or imbalance. So all I'd say is that whenever there's a move, regional migration, which has been going on a lot, by the way, in the last year, I mean, even among our fleet, is that the first step or two, you have to have either conviction in it or not. And if you don't, then there will be, you know, some frat company somewhere that will feel it. But if it's a balanced market, there will be another home for any displaced fleet. And That part of it, our customers, I think, understand that better this time than they did last year. So all I'd say is our track record of kind of looking at this macro is pretty good. We've been skating to where we said the puck was going to be and knock on wood, you know, kind of been right about it. So we're very cautious about not being wrong about it. But I'll also say it's not necessarily that everybody needs to get a price increase. Many times you get the same impact. of a price increase by improving contractual terms that were clawing back what maybe conceded in the past, you know, around minimums and hours that you would succeed, how you handle white space in the calendar, how is nonproductive time managed. You know, and I'd also say that the big dynamic that we often don't think about when you're looking at the whole macro is the dynamic for natural gas-powered fleets natural gas-fueled fleets. It's way different. It's supported by an arbitrage of as much as $10 million a fleet, where there's $10 million that a customer could pay substantially more for a fleet, yet show a lower cost. And I saw an EMP recently announced that they were going to make a change in 2023, and they were going to see some deflation. And that's what they're talking about, I think, is where they are going to be paying the frack company more. The frack company will get a good return, and the customer is offsetting it with his portion of that lower fuel cost. So it's a win-win if there ever was a definition of one, and that's more and more becoming a big part of the fleet. For us, it's more than half of our fleet has got natural gas support that way. So I may be talking a little bit of our book overall, but at the end of the day, my comments around the macro aspect sustained that I believe the whole fleet is in that arena. And moving out of gas into oil at this particular part of the cycle is going to be fine.
spk02: Yeah, and I think what you emphasized here is that there's a lot more nuance to it in this cycle run than there might have been four, five, six years ago in terms of the discussions that you're having with E&Ps, right?
spk05: That's exactly right. And The EMPs understand that clearly because they're the ones having the right to check, and they can see the fuel cost bill is way down and the frack fleet costs up a little bit. But we still, back to that point, not back to our net pricing pre-COVID, I mean, we're not part of the inflation story until we get back to at least that number. So I feel like we're not part of the problem here for them.
spk03: All right, that's great color. Thanks, Robert.
spk07: Our next question is from Saurabh Pond of Bank of America. Please go ahead.
spk00: Hi, good morning. Hey, Robert and Kenny. Just a quick one for me. It's kind of following up on Kurt's question on pricing, and I'm trying to understand the full year 2023 guidance. I think if I caught it correctly, you said you expect EBITDA to be up 40 to 50% in 2023, which is basically in line with the implied EBITDA, right? Based on your free cash flow and capex number, it's about $920 to $985 million. And I'm just trying to do a EBITDA per fleet math that implies about $30 million per fleet on a flat 32 fleet basis versus the fourth quarter, right? I'm comparing that with $26 million in the fourth quarter. Can you help us through the moving pieces on how we get from 26 to 30, basically trying to understand what's baked into that from a pricing perspective, from an efficiency perspective, and from a website integration perspective?
spk05: I'm glad you asked that question that way because at the end of the day, I can see how it might be confusing to see that a company's not spending very much money in growth CapEx and being able to demonstrate that kind of year-over-year increase. And when you look at it, Where we are as we exit 2022 and project that on an annualized basis, it doesn't take very much price or efficiency to get to the kind of numbers that you were talking about. But I do want to try to emphasize one more time about I would encourage people not to get overly caught up on the fleet count because I think you'll see ours move two or three up or down during the year with exactly the same amount of horsepower deployed. There is a significant number of fleets operating in U.S. land today that are operating with less than the number of pumps that they would like to have, and the customer would gladly pay for a couple more. There are cases where deploying horsepower into that kind of arena is better than configuring a bunch of them into a new fleet and going out less than maybe ideal. So we're going to be... And our economics, we run on a per horsepower or per pump basis as opposed to per fleet. But long answer, I'll let Kenny get into a little more of the mathematical details there. Just think about it being largely price and building off the already established run rate with the one additional electric fleet hitting the market now in Q2 instead of Q1.
spk01: Look, I'll just add, and just to highlight from our investor deck, you know, it's not just about EBITDA profitability or EBITDA profitability on a perfectly basis. We're focused on generating returns and cash flow, and that's our goal through this cycle is to generate all three, right? And that's one of the reasons why we put out that deck is to kind of show some other perspectives around financial performance of both the sector and next year.
spk00: Yeah, no, Robert, I appreciate you said that because that EBITDA for fleet metrics is becoming increasingly less relevant because the numerator and the denominator are both becoming hard to compare across companies. So I totally appreciate that point. Just a quick unrelated follow-up. I think you said somebody's question, it has benefited you that you have been slow on the electric fleet front, right? I wanted to follow up on that and think through What are you looking at from a technology standpoint? Are there other technologies out there that you are testing, trialing? And then just on the E-Fleet front, how do you think about leasing versus owning? And what do you think is the right answer for you on that front?
spk05: Well, look, I think it depends on the terms, of course, which one is the best. All the time, we would be looking at how it impacts our returns to make any decision like that. Technically, I would just say it's more about the financial around how you power an electric fleet. There's numerous different electric options out there, but they're not hugely different when it comes right down to it. I think they're all going to be pretty effective in balancing a lower fuel consumption or a lower fuel cost and a lower operating cost in general over time. It's just that when I said we were going slow, I meant not slow technically, more slow financially so that we could harvest Tier 4 DGB. And I'll just argue, I don't know when that ends. It seems like Tier 4 DGB might be a good investment long term. But I think for us that we've got to keep balancing that with how power evolves. If you get to a point where there's a grid out there and there's a number of customers working in that direction, that you can plug an electric fleet in and you don't have to take the power generation out there, then that's going to be a really good dynamic for FRAC financially. So that's the kind of thing we're balancing.
spk00: Okay, okay, okay, perfect. And just a quick clarification, Robert. The first fleet that's coming on in the second quarter, have you said if that's purchased or is that leased?
spk01: Yeah, this is Kenny. So we've said publicly our first E-Fleets on capital lease, about $30 million of its finance and about $10 million in the CapEx budget. Look, we negotiated that about a year ago. We're very pleased with the terms, and it's going to allow us to match the cash flow ins and outs. But, yeah, that's what our first fleet is.
spk00: Okay, okay, okay. Thanks, Kenny. Thanks for clarifying. Okay, guys, I'll turn it back. Thank you. Have a good day.
spk07: Again, it is star than one to ask a question, and our next question is from John Daniel of Daniel Energy Partners. Please go ahead.
spk09: Good morning, and thank you for including me. Quick question. You point out, rightly, the supply chain headaches that are out there, and it sort of begs the question, at what point do you have to start planning your orders for 2024? I'm not looking for a specific capex dollar. I'm just asking just the strategy from a procurement standpoint.
spk05: I think pretty much now, man. I mean, at the end of the day, giving visibility to your supply chain, just like our customers can do it for us, it helps everybody plan and organize accordingly. So I would argue that, yes, that is probably true. And I'd say a lot of people did 23 very early. We did 22 very early, and I would say we probably should have moved up 23 even earlier than we did. But it's going to depend. It doesn't matter if you order it or not right now. Getting clarity on their ability to catch up. And I think there's probably more down assets now as a percentage of total than there's probably that I've seen ever, maybe. So they've got to catch up with that first and then new bills. I'm not even thinking... There's much risk in 24 having a lot of wave of new bills coming just simply because of that.
spk09: It would seem to me, and you point out the new capacity, but when you think about the lead times, companies such as yourself having the wherewithal to place orders now to be in the front of the queue, it just seems like the larger companies, in theory, it's not meant to sound anti-competitive, but you can tie up the supply chain a bit more and it does limit if I'm not mistaken, the number of new entrants that could actually practically come on into the market. I don't know if you would care to comment on that, but it just seems reasonable to me.
spk05: Yeah, I think it seems reasonable to me as well, John. I'd just say that I think I've seen it play out a little bit in the market when you look at maybe some of the M&A deals that have been done with smaller guys who basically had seen their fleet count drop over time against their will, maybe, because they're unable to access the parts necessary to keep the whole thing running. I think you extrapolate that into your question, and I think that's the same answer.
spk09: Okay. Can I squeeze two quick ones in here real quick? I don't know if you've got a long line behind you.
spk05: This is our last question. I mean, you're the last guy, so let's go ahead.
spk09: Thank you. Thank you. Thank you. So in the incremental demand of 20 to 25 fleets, I'd hate to be nuanced, but how much of that is actually truly for dual fuel versus legacy tier two? Does that make sense? So it seems like more of the demand is for the better.
spk05: Well, look, I would say that we ain't looking at it like, yeah, that's a macro of the fleet count. If the customer had a choice, it would be 100%. fuel or electric. Whatever can burn natural gas, put it that way.
spk09: Fair enough. And the last one, can you just update us on sort of your thoughts on any differences, competitive differences between Delaware and Midland Basin, what you're seeing sort of leading edge out there? From what perspective? Just from activity, from thoughts of competitors maybe shying away from Delaware Basin type work because of it more in you know, intensity, if you will, on the equipment. Just have you seen any demonstrable change in competitive landscape? And what would you expect?
spk05: You know, I think everybody's looking for who can get the best kind of efficiency, pumping hours per fleet per month on average. You know, we made a number of changes in our home fleet as we went into 23, and some of that was migration within the basin, looking for customers of like mind that were focused on, you know, the whole supply chain working in unison and absorbing the integrated model and being able to pump in day in, day out. The difficulty of the fraction factor in there, for sure, and it has to be captured either in price or something, or you would have differential performance financially, one frack fleet to another in hard versus easy fracking. So, yeah, I suspect there's some of that.
spk09: Fair enough. Well, I appreciate you making time for me. Thank you. Appreciate the call. Yes, sir.
spk07: This will conclude our question and answer session. At this time, I'd like to turn the conference back over to Robert Drummond for any closing remarks.
spk05: Thank you very much, everyone, for participating in today's call. I really do want to thank the entire Next Year team for your efforts, and we remain committed to making Next Year a place where you're going to find opportunities for a long and fruitful career. Thank you very much.
spk07: The conference has now concluded. Thank you for attending today's presentation, and you may now disconnect.
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