Archrock, Inc. (NYSE:AROC) Q3 2025 Earnings Call Transcript

Archrock, Inc. (NYSE:AROC) Q3 2025 Earnings Call Transcript October 29, 2025

Operator: ”

Megan Repine: ”

D. Childers: ”

Douglas Aron: ”

James Rollyson: ” Raymond James

Douglas Irwin: ” Citi

Timothy O’Toole: ” Stifel

Eli Jossen: ” JPMorgan

Gabriel Moreen: ” Mizuho

Michael Blum: ” Wells Fargo

Nate Pendleton: ” Texas Capital

Joshua Jayne: ” Daniel Energy Partners

Steve Ferazani: ” Sidoti

Elvira Scotto: ” RBC Capital MarketsGood morning, and welcome to the Archrock Third Quarter 2025 Conference Call. Your host for today’s call is Megan Repine, Vice President of Investor Relations at Archrock. I will now turn the call over to Ms. Repine. You may begin.

Megan Repine: Thank you, Julianne. Hello, everyone, and thanks for joining us on today’s call. With me today are Brad Childers, President and Chief Executive Officer of Archrock; and Doug Aron, Chief Financial Officer of Archrock. Yesterday, Archrock released its financial and operating results for the third quarter of 2025. If you have not received a copy, you can find the information on the company’s website at www.archrock.com. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on our current beliefs and expectations as well as assumptions made by and information currently available to Archrock’s management team. Although, management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. In addition, our discussion today will reference certain non-GAAP financial measures, including adjusted net income, adjusted EBITDA, adjusted EPS, adjusted gross margin and cash available for dividend. For reconciliations of these non-GAAP financial measures to the most directly comparable GAAP financial results, please see yesterday’s press release and our Form 8-K furnished to the SEC. I’ll now turn the call over to Brad to discuss Archrock’s third quarter results and to provide an update of our business.

D. Childers: Thank you, Megan, and good morning, everyone. Third quarter performance again demonstrated the strength of our operations and the natural gas and compression markets. The U.S. natural gas infrastructure build-out continued to support robust third quarter and full-year 2025 performance, and we expect this to continue into 2026 and beyond. At Archrock, customer service remained outstanding, operational execution excellent and profitability at high levels. We continue to expand our adjusted EPS and adjusted EBITDA during the quarter. Compared to the third quarter of 2024, we increased our adjusted EPS by 50% and our adjusted EBITDA by more than 46%. Our contract operations and Aftermarket Services segments both delivered impressive revenue and gross margins due to strong activity levels, a supportive pricing environment and the efficiency improvements we’ve driven across our operations.

We maintained our sector-leading financial position, including an attractive quarter end leverage ratio of 3.1x, driven by the stability of our cash flows. Our quarterly dividend per share was up 20% compared to a year ago, and we maintained robust dividend coverage of 3.7x. We also continue to accelerate the repurchase of shares on the confidence we have in the durability of natural gas demand, compression market strength and Archrock’s competitive position. Since the inception of our share repurchase program in April of 2023, we’ve repurchased more than 3.9 million shares of common stock at an average price of $20.21 per share. I’m both excited by and proud of the level of operational and financial execution we are achieving, which is also giving us strong momentum heading into 2026.

Day-to-day, we remain focused on driving the next increment of Archrock’s success through our first-rate customer experience, implementation of innovative technology and our returns-based capital allocation. When coupled with the opportunity-rich market for compression, we believe we are in today and see for the period ahead, we believe that Archrock is set up for an extended period of strong and sustained growth in earnings, free cash flow and returns to our shareholders. With that overview, I want to dive more into the constructive compression dynamics we see on both a short- and a long-term basis. Beginning with the short term. The current environment is characterized by commodity price volatility, oil rig count declines and the possibility that oil volumes could flatten or even decline slightly in 2026.

Should this scenario play out, however, we still expect natural gas production growth in the U.S. with a rate that is likely in the low single digits, including continued gas production growth in the Permian Basin. The dynamic of natural gas production outpacing oil production is one that is consistent with historical trends in other more mature associated gas shale plays like the Eagle Ford and the Bakken, where rising gas-to-oil ratios have led to natural gas volume growth long after oil volume peaks. Because of this, we expect short-term gas market fundamentals will require a similar amount of growth investment by the industry and Archrock during 2026 compared to 2025, a point I will return to in a bit. Shifting to the long-term, we believe the compression industry has entered a durable upturn driven by natural gas demand growth and bolstered by the pervasive level of capital discipline across the energy complex, including by the producers, midstream operators and compression service providers.

Expanding on natural gas demand growth, in particular, we see visible growth in U.S. LNG exports and emerging demand for AI-driven power generation. Combined, we expect these demand pressures will require a significant call on U.S. natural gas production to the tune of an incremental 20 to 25 Bcf a day by 2030, depending upon the forecast and with similar levels of growth likely into the next decade. First, on LNG export facilities. U.S. demand is expected to grow by more than 17 Bcf a day by 2030, much of which is already under construction and at least another 6 Bcf a day of projects could be operational before 2035. Second, the proliferation of AI is creating a new and meaningful source of domestic energy demand and the opportunity for natural gas production and infrastructure to play a critical role is becoming more tangible.

We’ve now seen hundreds of data center projects announced across the U.S., driving a virtual arms race for power. This includes investments in new power plants by utilities and more recently, natural gas pipeline expansion and direct power generation projects to meet this growing demand. Variation in the forecasted magnitude and timing of this opportunity remains wide, but the risk forecasts through 2030 are significant, totaling up to 10 Bcf a day with additional growth expected well into the next decade. Simply put, we need all the gas we can produce, transport and therefore, compress. At Archrock, we expect to fully participate in these developing markets and are increasingly encouraged by these leading indicators for our business. Moving on to our contract operations segment.

Our fleet is younger, larger and positioned in competitive basins with high-quality customers. This is translating into enhanced performance across several fleet metrics. First, utilization. We remained fully utilized during the quarter with utilization exiting at a rate of 96%. I’m proud to share that we’ve maintained utilization in the mid-90s range for the past 12 quarters. Second, stop activity. Stop activity year-to-date remains at historically low levels. Third, time on location. Based on 2024 data, the average time at Archrock compressor stays on location is now more than 6 years, representing a 64% improvement since 2021. With the investments we’ve made to high-grade the quality of our fleets and given what we see in the market today, we expect these recent trends in utilization, stop activity and time on location to continue into the foreseeable future.

At quarter end, we had 4.7 million operating horsepower. As a reminder, on August 1, we completed the sale of several small high-pressure gas lift units for $71 million. Excluding this and other active asset sales, we grew horsepower organically by approximately 56,000 horsepower on a sequential basis in the quarter. As we look ahead, we have a substantial contracted backlog and continue booking units for 2026 delivery to meet strong customer demand led by the Permian Basin. Spot pricing continued to increase during the quarter, and as our team remains focused on achieving market rates for all of our units, rates on our active fleet also moved higher. Now as many of you track trends in quarterly revenue per average operating horsepower per month, I wanted to point out the impact of the recent acquisition and divestment activity on that calculation this quarter.

As I mentioned, pricing on our installed base of compression increased sequentially in the quarter. Third quarter 2025 revenue per average operating horsepower per month declined slightly compared to the second quarter of 2025, however, due to 2 factors. First, the average size of our compression units increased from 899 horsepower per unit to 927 horsepower per unit in the quarter, which was primarily the result of the high-pressure gas lift unit sale I just mentioned. Second, the full quarter impact of NGCSI fleet acquisition, that we had an average pricing on an equivalent unit basis a bit lower than the Archrock fleet, but we believe this gives us the opportunity to bring rates on those units up to market over time. Concurrent with the decline in revenue per average operating horsepower per month, as you would expect, part of the cost per average operating horsepower per month decline we experienced in the quarter was also due to this increase in average horsepower size.

We achieved a quarterly adjusted gross margin percentage of 73%. Strong pricing and solid cost management drove underlying contract operations gross margin to 70.4%, up slightly from the prior quarter. Third quarter 2025 adjusted gross margin further benefited from a $9.9 million cash tax credit, which is the driver of the gross margin increase from the 70.4% level to the reported 73% level. In the Aftermarket Service segment, the large base of owned compression continues to support strong AMS activity, particularly in contract maintenance and service work, and great customer service is driving repeat business. Third quarter 2025 AMS gross margin percentage remained at impressive levels and was consistent with guidance. Shifting to our capital allocation framework.

We remain committed to our prudent and returns-based approach. The successful execution of this capital allocation strategy has put us in a position to generate positive free cash flow after dividend moving forward. Over the long term, we are committed to positioning and managing this business to generate positive free cash flow and increase returns to our shareholders. Now more on our objectives as we look into 2026. We see an opportunity-rich market ahead and the IRRs at which we expect to invest new build capital remain robust. As I mentioned earlier, the average compressor time allocation has extended to more than 6 years, which is beyond our expected payback period on new investments. Our investments continue to be underpinned by multiyear contracts with blue-chip customers in highly profitable basins.

As we indicated last quarter, we expect 2026 growth CapEx to be not less than $250 million and within the range of investment levels that we’ve made annually since 2023. We believe this is the level of CapEx required to support the infrastructure build-out we are experiencing in the U.S. in order to satisfy the growing demand for natural gas described earlier. As we invest in these compelling opportunities, we’re committed to maintaining an industry-leading balance sheet and plan to maintain a target leverage ratio of between 3x to 3.5x. At the same time, we’re delivering on our promise to provide an ongoing and growing return to our shareholders through the payment of a quarterly dividend. We will continue to also use buybacks as an additional tool for value creation for our shareholders.

We’ve returned $159 million to stockholders through dividends and share repurchases during the first 3 quarters of 2025, compared to $93 million at this time last year. Given our confidence in the company’s strategy and our commitment to returning capital to shareholders, the Board has approved a $100 million increase to our existing share repurchase program. After accounting for the recent repurchases during the third quarter of 2025 and in October, with this additional authorization, our current capacity is approximately $130 million. In summary, 2025 continues to be a tremendous year for our company, and I’m as optimistic as I’ve ever been about where we can drive this business in 2026 and beyond. As the structural growth in natural gas production and compression continue to take hold, we are focused on growing our business, growing our attractive and durable earnings power and growing our free cash flow generation.

With that, I’d like to turn the call over to Doug for a review of our third quarter performance and to provide additional color on our updated 2025 guidance.

Douglas Aron: Thank you, Brad, and good morning. Let’s look at a summary of our third quarter results and then cover our updated financial outlook for 2025. Net income for the third quarter of 2025 was $71 million. Excluding transaction-related and restructuring costs and adjusting for the associated tax impact, we delivered adjusted net income of $73 million or $0.42 per share. We reported adjusted EBITDA of $221 million for the third quarter of 2025. Underlying business performance was strong in the third quarter as we delivered higher total adjusted gross margin dollars on a sequential and year-over-year basis despite the lost revenue and profits from a larger asset sale during the quarter. We reported a $4 million net gain on the sale of assets, which was offset by $4 million in other expense and related to an amendment fee for our MaCH4 natural gas liquid recovery new venture agreement with our partner.

Turning to our business segments. Contract operations revenue came in at $326 million in the third quarter of 2025, up 2% compared to the second quarter of 2025, driven by growth in horsepower and pricing, and revenue would have been up even more at 4% sequentially, absent the sale of active horsepower, as Brad discussed. Compared to the second quarter of 2025, we grew our adjusted gross margin dollars by more than $17 million. We expanded our adjusted gross margin percentage by approximately 73%. Underlying operating profitability was 70.4% in the quarter, up slightly compared to the second quarter of 2025. Results further benefited from the receipt of a $9.9 million cash tax settlement. In our Aftermarket Services segment, we reported third quarter 2025 revenue of $56 million compared to the second quarter of ’25 of $65 million, but up 20% from $47 million in the year ago period.

Third quarter 2025 AMS adjusted gross margin percentage was 23%, consistent with the second quarter of 2025 and consistent with guidance. Turning to our balance sheet. Our period end total debt was $2.6 billion and available liquidity totaled $728 million. As previously announced in October, we intend to take advantage of the lower rate environment and use existing capacity on our ABL facility to redeem all $300 million of our outstanding senior notes due 2027 at par. The redemption date for the notes will be November 17, 2025. Our leverage ratio at quarter end was 3.1x calculated as quarter end total debt divided by our trailing 12-month EBITDA. This was down from 3.3x at the end of the second quarter of 2025. With continued strong performance in our business, we expect to continue deleveraging as the year progresses.

We recently declared a third quarter dividend of $0.21 per share or $0.84 on an annualized basis. This level was consistent with the second quarter of 2025 and represents a 20% year-over-year increase. Cash available for dividend for the third quarter of 2025 totaled $136 million, leading to impressive quarterly dividend coverage of 3.7x. In addition to our quarterly dividend payment, we repurchased approximately 1.1 million shares for approximately $25 million at an average price of $23.18 in the quarter. Including the additional $100 million authorization, this leaves approximately $130 million in remaining capacity for additional share repurchases on the replenished authorization as of October 22. Turning to our updated outlook. Archrock increased its 2025 annual guidance to reflect continued outperformance during the third quarter of ’25 and our expectation for continued strength in our underlying business during the fourth quarter.

As a reminder, our guidance reflects 8 months of contribution from the NGCS acquisition and outperformance in our business, partially offset by the removal of 5 months of contribution from the high-pressure gas lift units we sold. We are raising our 2025 adjusted EBITDA range to $835 million to $850 million from the prior range of $810 million to $850 million. Additional detail can be found in our earnings release issued last night. Turning to capital. We are narrowing our growth CapEx guidance range to between $345 million and $355 million to support investment in new build horsepower and repackage CapEx to meet continued customer demand. Our growth CapEx is underpinned by multiyear contracts. Maintenance CapEx is forecasted to be approximately $110 million to $115 million.

We also expect approximately $35 million to $40 million in other CapEx, primarily for new vehicles. Total capital expenditures are expected to be funded by operations and further supported by non-strategic asset sale proceeds, which total more than $114 million in 2025 year-to-date. In summary, as the structural growth in our natural gas production and compression continues to take hold, we are focused on finishing out the year strong and setting a solid foundation for even higher levels of customer service, operational execution and financial performance in 2026. With that, Julianne, we are now ready to open the line for questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from Jim Rollyson from Raymond James.

James Rollyson: Great job as usual. Brad, you’re in an interesting position where it’s kind of the first time that I can recall in a long time where you guys generated free cash flow, and as you mentioned, you’re set up to do that going forward. At the same time, you’re at the bottom end of your leverage goals and you’re basically set up to just continue to put cash. I’m curious how you think about deploying that. Obviously, you’ve been growing the dividend, and there’s obviously room for that to continue to grow even today. You just expanded the repurchase program. You’ve been active in M&A, but maybe just a little color about how you think about that given the kind of unusually strong position that you’re in today.

D. Childers: Thanks, Jim. I appreciate it. I’m sure you don’t want to expand on that question anymore because I love the way you asked it. We have a tremendous opportunity to create value for our shareholders. When we look at our capital allocation priorities, our absolute best use remains investing in and growing this business. The returns that we get by growing our fleet organically by expanding our footprint with our great customers remains our best — the best return we can generate for our investors going forward. We have the additional tools because we are generating sufficient cash. We have great coverage. I think we exited 3.7x what I talked about. We have a tremendous opportunity to continue to grow our dividend over time.

As we’ve demonstrated in the past, it’s up 20% on a year-over-year basis. We can grow that over time as we continue to grow our business. In this market today, the macro is dislocation to our stock price, giving us also the opportunity to deploy capital and buying shares when the market is not valuing it appropriately. We get to buying shares with this complicated oil market and this dislocation and generate additional and great returns for our investors that way. We intend to use all 3 tools for capital allocation going forward, but the priority is, we get to grow our business. The market that we see ahead for natural gas demand is tremendous, and that’s what we expect to do with most of our cash.

James Rollyson: Appreciate that color. Then maybe my second question, just circling back to margins. Even without the tax benefit, you topped 70%. My math on midpoint of guidance implies 71.5% for 4Q. Maybe just a little color about some of the things that are helping drive this outside of just pricing gains and sustainability and upside. We’ve had this discussion, I think, off and on every quarter because you keep having better and better margins, but just curious the latest state of the union on margin opportunity.

D. Childers: The first comment I want to address is that this business, the base business, absolutely outperformed without the tax benefit. We saw that in the roughly 70.4% gross margin that we delivered, which was delivered over a combination of continuing pricing prerogative as well as excellent cost management by our teams throughout the organization and especially in the field. That outperformance that you cited is absolutely independent of the tax benefit that we got to claim back, which is a cash tax benefit. Now on the substance of your question, One of the biggest drivers beyond pricing that we have in our operation today is we have been investing in a very disciplined way over the years into technology, the combination of telemetry sensors on the edge on our equipment, a big data engine that gets to sort through the data and help us prioritize our customer service so that we can maintain better run-time for our customers for the benefit of our customers as priority one, but also we drive a lot more efficiency in how we are touching the units.

The units are telling us more and giving us more information. Our mechanics are able to dispatch in a more efficient way, well-equipped when they arrive on location and it just creates a much more cost-effective approach to managing the operation. We’ve gotten the benefit of those investments in our numbers today, and we expect to continue to drive improvement in those numbers in the future based on those investments in technology.

Operator: Our next question comes from Doug Irwin from Citi.

Douglas Irwin: I wanted to maybe start on the demand side, and I know you kind of touched on it in your prepared remarks already. We’ve seen an uptick in LNG project FIDs and data center announcements over the past couple of months. These are obviously drivers you’ve been talking about for a long time now. Just curious if some of that recent activity has maybe translated into an acceleration in some of the discussions you’re having with customers on your end? Then just generally, how that momentum might impact the way you’re thinking about your multiyear growth outlook and especially kind of where and what basins that growth might be coming from moving forward?

D. Childers: Sure. Thank you, Doug. Look, what I said in my prepared remarks, I can expand on just a little bit, the point the market is giving us today is that the world is short of power, and that is driving robust demand for LNG. That’s a global phenomenon. We like to say at Archrock, we power a cleaner America, and now with so much of our natural gas going into the form of LNG — exports of LNG, we know we’re also participating in powering a cleaner world, and we’re very proud of that. That LNG demand is spiking, and we’re seeing just a tremendous amount of demand generated there. By the way, we’re also seeing growth in — I think we had peak exports to Mexico in the quarter as well, so it’s not just LNG. We’re also seeing pipeline gas going to Mexico.

Then on the AI data centers, what’s interesting about the wide variation in forecast is that the forecast ranges from a low of 3 Bcf a day to 2030, which I think most people think will blow through, up to 12 Bcf a day of incremental demand through 2030 and then at least that much again beyond 2030. What we’re seeing today is an acceleration in pipes, LNG facilities, FIDs, as well as data centers. What we’re also experiencing is the buckling of the pressure of we’ve underinvested in infrastructure. We’ve underinvested in infrastructure in pipes, in power, and that really has to catch up. The pressure we’re seeing on our business is a really excellent immediate interim and long-term demand for our units. That’s translating to be concrete now into our CapEx guidance of a minimum of $250 million for 2026, which is consistent with our levels for 2025, but we see that we have a lot more confidence in the multiyear growth scenario ahead, deploying that level of CapEx to help support this expanded infrastructure requirement for power and for LNG exports.

Douglas Irwin: Then maybe for a follow-up, I guess you’ve talked a few calls in a row now about units staying on location longer-and-longer than they did even just a few years ago. Just curious if you’ve seen this translate into increased customer demand for longer duration contracts, even if it’s maybe just a shift towards the higher end of your typical 3- to 5-year contract range that you talk about. Then just curious if you can maybe comment on how you’re thinking about the right mix of month-to-month versus long-term contracted capacity moving forward.

D. Childers: The good news is, as we discussed, that our units are staying on location now greater than 6 years, which is a few things — a few aspects that are important about that. One is that it’s a market improvement over the past. This really reflects Archrock’s focus and shift to large horsepower installations and the midstream infrastructure position that this business now occupies today, which means that we’re going to stay on location longer. We’re going to have tremendous stability in those operations as we become an integral part of our customers’ operations and capital stack. That’s the benefit of the investments we’ve made into large horsepower over time. The contract terms remain in the 3- to 5-year range, but yes, because it’s predominantly large horsepower, these are large capital investments, we have seen it move to the higher end of the 5 years on entry into these contracts, but we have not either seen and we have not tried to drive a shift in those contract terms.

The important point about the position we have with our major customers is that it’s not just about those contract terms on the individual location contracts. It’s also that with our largest customers, we have a strategic position and a master services agreement, which builds a longer-term relationship. It gives us the confidence given how critical we are in our customers’ operations today that our units stay on location as long as they are operationally required independent of contract term, so it’s that time on location. It’s the fact that it costs a lot of money that the customer has to bear to switch out a unit that is giving us that longer live application on location and generating much more stability over time.

Operator: Our next question comes from Selman Akyol from Stifel.

Timothy O’Toole: This is Tim on for Selman. Congrats on the quarter. Just wanted to get an update on how lead times are trending. Just wondering if there’s any update to that.

D. Childers: Yes. The gating item for lead times remains Caterpillar engines predominantly for our gasifed engines. Those are in the 60-week lead times now we order a new unit from Caterpillar. There are some units available in the market that we can get sooner just because with all this pressure right now for growth, people are ordering equipment, the packagers are maintaining a bit of equipment available. That will get sucked up pretty quickly though or used up pretty quickly. There’ the lead times are 60 weeks with a little bit of opportunity in the market to grab engines from others if we needed to.

Timothy O’Toole: Then just my follow-up. Curious on how some of the customers are maybe shifting behavior in a lower crude environment. Are you seeing any more outsourced opportunity? Or is there any changes to the AMS business? Are they looking to defer some of those costs? Just curious on real-time changes in customer behavior.

D. Childers: Sure. Other than the seasonality of order activity, what I mean by that is that customers are in the — right now are in the budget preparation time for their 2026 business plans. I think we are now in the phase where we’re working with our customers on their new equipment needs, on pricing discussions that are starting to occur. It’s at this time of the year and also candidly, we have the holidays this time of the year where we see a little bit of slowdown as people are gathering their plans together. Aside from that, we’ve seen no major shifts in either the allocation of capital by the customers using an outsourced compression provider like us or in-sourcing their own capital or their own compression equipment.

We see no major shift in AMS activity. That still remains robust. The industry is so highly utilized with us at 96%, our competition at high levels of utilization, our customers’ fleets at high levels of utilization, we’re seeing activity in both contract ops and AMS at high levels to make sure we’re keeping the gas moving and keeping the equipment serviced. We’ve not seen a change in that at a macro level.

Operator: Our next question comes from Eli Jossen from JPMorgan.

Eli Jossen: I wanted to touch on the extended time on location you’re seeing from your customers and you talked about it in your opening remarks. Obviously, that reflects really strong utilization and demand from those customers, but can you talk a little bit about how it impacts recontracting? Obviously, we’re seeing the dollar per horsepower per month broadly move up into the right, but just how should we think about overall recontracting discussions with those customers?

D. Childers: Sure. I mean I think there are 2 components to the recontracting question in my head. The first is recontracting that unit so that it stays on location longer. I’m going to point out that even with the — greater than 6 years’ time that we’re achieving, that includes with a mix of horsepower that’s smaller. As we continue to add more large horsepower, my expectation is — my belief is that we’re going to see that time on location continue to grow and expand. The second component to recontracting, I think, which may be at the heart of your question is really what happens to pricing and what’s the opportunity to drive pricing going forward. On the good news front, the way we’ve structured our contracts, the vast bulk of our large strategic accounts include pricing mechanisms built into the agreement, so that either we reprice on an index or we have a repricing opener.

Then with our nonstrategic accounts, we have the ability when they roll off a contract to redo pricing. On a percentage basis, as in prior years, it remains fairly consistent because of the way we structured the business that we get to reprice annually, 60% to 65% of our contracts are open for repricing, either through a negotiation built into the contract, an index built into the contract or as they roll off their primary term. We’re quite optimistic that in this market that at the high levels of utilization we’re achieving that we will have the ability to continue to drive pricing forward and certainly in 2026.

Douglas Aron: Eli, this is Doug. I may make another point that we really haven’t talked much about, if at all, on this call, and that is the level of stop activity or units getting returned. We really are seeing that at historically low levels. That’s a function of a lot of different things, but most notably, gas volumes are growing in the U.S., and there’s just a real lack of available equipment. Archrock at 96% utilization, the industry at a very similar level, I think our customers have started to understand there’s a real need to plan in advance for units, and so part of the contracting is that if we don’t have units that are stopping on location, we don’t have those available to rebook. All of that, as Brad talked about, leads to an opportunity to continue to reprice. I think, again, if you think about that utilization for the industry as the best sign of just, frankly, how healthy this business is, and we expect it to continue to be.

Eli Jossen: Then maybe just in that contracting equation, flipping to the cost side, I just wanted to get a sense how input costs are trending. Obviously, the OEMs like Caterpillar, we can expect there’s some inflation in those businesses. I know you guys are obviously able to pass along a lot of those costs, and that’s what we’re seeing — part of what we’re seeing in the dollars per horsepower per month equation, but just if you can frame the way that costs are trending in the business, maybe in the Permian versus elsewhere and what that does to margins in the longer term?

D. Childers: The costs overall are trending at what I would say is a normalized level of inflation, and that’s in the low single digits. That’s what we’re seeing out of the OEMs, both for new equipment and as well as for parts and materials going forward. Lube oil pricing, as you would expect, has actually moderated given the lower crude oil pricing today. Finally, the only one that’s the exception of that is labor costs, especially in the Permian, still run in the mid-single digits. There’s more pressure there just because labor is so short, so tight in the — overall in the energy industry and certainly in the Permian, so that’s the way costs are running. It’s a very manageable level right now. It feels like a very comfortable level to build in and budget for, I think, for our customers, but also for us. You’re right, we do expect to have the ability to continue to pass on and share cost increases through rate increases over time.

Operator: Our next question comes from Gabe Moreen from Mizuho.

Gabriel Moreen: I just want to circle back on capital return a little bit. Any thoughts — you’ve been really good opportunistically here, I think, at share buybacks. Any thoughts to making it, I guess, more programmatic and on a related basis, I’m just curious, Doug, if there’s any lower bound leverage level that you just don’t want to go below that floor? Or were you just thinking, hey, we’re underlevered here and our balance sheet could take more on at these levels?

Douglas Aron: Yes. Look, fair question, Gabe. I think Brad outlined, we really believe we somewhat uniquely even in the compression space are positioned to be able to do all of the above. That being deploy capital to our customers, grow our dividend and ask our Board for an incremental $100 million share authorization. I think we’ve been pretty consistent repurchasing shares quarterly. I don’t certainly want to share exact specifics of where and at what target price. Look, as you point out, our leverage is trending towards and headed to even below our target range, which means that not to say we won’t end up below that for some period of time, but we have both the luxury and the desire to do all of the above. I think you should expect to see us continue to do that.

Gabriel Moreen: Maybe, Brad, if I can ask an open-ended question. You talked about the arms race around power gen. It seems like not a week goes by where there’s not some sort of creative solutions to get near-term power to procure to those who demand it. Just curious if Archrock is looking at, in some way, shape or form, participating more directly in that power procurement. Again, open-ended question, but I’ll leave it at that.

D. Childers: What we’re excited about for the future is the amount of power that is going to be required is going to require the production and the increased production growth in natural gas. That is where we are focused in deploying compression to support natural gas to help support the power growth. The unique position of the industry today is that only natural gas can respond as quickly as is needed to deliver on an intermediate and I think also a long-term basis, but on an intermediate basis, the amount of feedstock required for the dense sharp, incredibly high demand growth for power that we see ahead. Our primary goal right now is to deploy our capital to grow our compression infrastructure business to support that growth. We’re excited about that investment opportunity, first and foremost.

Operator: Our next question comes from Michael Blum from Wells Fargo.

Michael Blum: Just wanted to ask about the $250 million CapEx for 2026. You obviously have very positive comments on the call, both this quarter and the outlook. Just curious if that’s just conservatism on your part? Or are there other factors at play that we should be thinking about?

D. Childers: Thanks for the question. It’s interesting in the past, I never would have thought a $250 million growth CapEx budget would be positioned as conservative. We consider it to be very consistent with the levels of CapEx that we’ve invested in the business at the high end of the CapEx levels we’ve invested in the business in prior years. I’ll point out that even though it feels like a step back from the $350 million midpoint that we’ve guided to in 2025, approximately $70 million of that CapEx budget and CapEx spend in 2025 is directly attributable to CapEx budgets that we inherited or CapEx expenditures that we inherited as part of the 2 acquisitions we made. When you think about the delta on our overall fleet compared to that, it feels much more consistent on a year-over-year basis and pointing out that we’re getting these huge cash flow benefits in from the 2 acquisitions we made without those requiring the same levels of CapEx that position this business before the acquisition.

We love that actual capital efficiency from the acquisitions. What you’re seeing on a year-over-year basis is probably more consistency than may have been apparent in the CapEx budgets, which give us a tremendous amount of growth with our core customers and in the marketplace. We’re excited about that level. Again, we pegged that as a minimum for next year. As I also pointed out, our customers — some of our customers remain absolutely in budget territory right now, so we’ll see how the rest of that shakes out.

Operator: Our next question comes from Nataniel Pendleton from Texas Capital.

Nate Pendleton: Congrats on the strong quarter. A lot of commentary has understandably been on the strong outlook for natural gas demand and moving that gas to end markets, but with a large amount of horsepower still dedicated to centralized gas lift, can you speak to how those markets are evolving?

D. Childers: Sure. With, I think, a slowdown in oil drilling and a flattening of oil production possible right now, we’re absolutely seeing a bit of a flattening in order activity attributed directly to gas lift, and we’re seeing much more of the demand right now on a mix basis toward gathering. I’ll point out that the great news is that when these units go out for to support gas lift and production, they remain out. As Doug pointed out, we said in our prepared remarks and Doug highlighted just a minute ago, our stock activity is at absolutely historical low levels. It’s a reflection of the strength of this business model that we are leveraged to production, oil for gas lift and natural gas for transportation. Both of those are absolutely at high levels of utilization and incrementally growing going forward.

Right now, as you would expect, we are seeing a bit of a pause in the oil-directed gas lift order activity in the mix. It’s still there, but it’s definitely at a lower level in the mix. We remain, however, optimistic that gas lift has become an absolutely critical component in the oil production system and that, that demand will come back as the market recovers.

Nate Pendleton: Can you provide more color about the MaCH4 natural gas liquid recovery amendment fee mentioned in the release and the progression of a few of those new venture investments?

D. Childers: Sure. On the MaCH4, particularly, the joint venture was structured where there was a minimum commitments to purchase equipment, and we wanted to change the timing of our commitments, so we basically just bought that out. That was the main impetus behind the amendment, so we pay a charge upfront to buy out the commitment and change the time frame for when those commitments will take place. On the MaCH4 itself, the good news is that we had a very successful pilot, and we’re in the early phases of getting the first units out to see if we can build enough of a commercial market. On the very exciting side, customer enthusiasm for the product is great. I’ll just remind everybody what this product does, is it takes a sliver of the natural gas that we would otherwise that we’re putting through our gas drive engines, and it takes out the heavy liquids, preserving the quality of the heavier liquids value to be captured downstream and provides residue quality gas for that compressor, which really helps with compression operations.

It also reduces the VOCs coming off that unit. It’s really an attractive product. We’re in those early phases right now, and we’ve received great support from the customers. On our other new venture investments, I’ve been clear in the past, what we are really focused on doing is changing the way we conduct business as an industry. keep the methane in the pipe and eventually put the CO2 back in the ground and our investments in Ecotec, which primarily is our handheld devices that allow us to detect methane and see the leaks to support [indiscernible] repair. That business continues to grow and is doing well. We talked about the MaCH4. Then the CARBON HAWK, which is a product that captures gas otherwise discharged the atmosphere to the flare in normal operations.

We’re absolutely seeing a bit of a slowdown in that — in market acceptance on that product just based upon the regulatory environment changes since we’ve had a change in administration, but we still remain optimistic that this is a very valuable product for the industry to keep the methane in the pipe instead of venting it to the atmosphere or sending it to the flare. Neither of the Ecotec or that one do we expect to be needle movers for us financially. We’ve built nothing into the forecast for that, but we do believe these products are incredibly valuable and useful to the industry to conduct the most sustainable oil and gas operations we can for the future.

Operator: Our next question comes from Josh Jayne from Daniel Energy Partners.

Joshua Jayne: First one for me. You’ve talked about the $250 million of CapEx for next year, and then also items like engines having 60-week lead times. I’m just curious, do you see a scenario in the next few years where the market maybe supports you spending, for example, let’s pick a round number, $400 million, $500 million in growth CapEx, all supported by contracts? Or is something like that level not really feasible because of supply chain constraints. Maybe you could just talk about that a little bit more.

D. Childers: That level of CapEx is foreseeable. I do believe that while there are constraints out there on equipment lead times and deliveries, I’m going to point out, we were at $350 million last year, inclusive of the CapEx budgets that we took over with the acquisitions of NGCSI and TOPS, and so the gap to get from 350 to 400 is completely foreseeable for the future for this industry. I do believe that while there are supply constraints, that level of CapEx could be achieved even within the existing supply chain.

Joshua Jayne: Then a shorter-term question. You highlighted the full quarter impact of the NGCSI acquisition that hurting some of your metrics in Q3. Could you just speak to when you expect the pricing of that fleet to essentially mirror the rest of your fleet? How long ultimately do you think that takes?

D. Childers: What we’re optimistic about is that we knew the — obviously, we knew the pricing of this when we acquired these units, and they still remain at excellent gross margins, and we will work with that customer base to drive those changes over time, but now it’s a part of our fleet. Now the separation has basically disappeared, and we will treat those operations like we would any other units in our installed base to drive pricing up over time. Then finally, I’m going to point out that with the NGCSI acquisition, in particular, we acquired units that were predominantly a majority of which were with one of our existing key customers with whom we have a great relationship. We expect to do that over time, but candidly, the separation of those units has now disappeared, and we’ll see that — we can see it in the quarter when it impacted us, but it’s going to be hard to track that going forward other than it gives us another chunk of units that will allow us to raise price and improve profitability over time.

Operator: Our next question comes from Steve Ferazani from Sidoti.

Steve Ferazani: I just wanted to ask now that you’ve successfully integrated NGCSI after the larger TOPS deal. Now that you’ve flexed those muscles, do you see other opportunities out there? Does it get easier? Or does it really always come down to whether the quality of the compression meets your standards?

D. Childers: Your latter point is correct. It really is driven by whether or not the fleet position and the potential of the acquired fleet fits our strategic position of focusing on large horsepower with the customer base that we’ve built and the geographic locations that we operate in and are excited about growing in, as well as the quality of the fleet age and the configuration. Those are the primary factors, starting with the strategic and then moving to the operational. That drives our analysis for sure. The other 2 components though that are interesting is that, the right opportunity has to be in the market at the time, and we have to have a willing seller and in a transaction that makes pricing sense. On the good news front, there remain other compression companies out there that are operating excellent fleets that are operating really well.

They’re building their own customer base. What you’re seeing in our business, which is absolutely supported by this market demand, other people have noticed too that this compression business is an attractive business and can drive great returns. I believe that could and should yield additional opportunities in the future that look something like either TOPS or NGCSI or others.

Steve Ferazani: Is there anything complementary services or equipment that could fit as well? Or will you remain compression?

D. Childers: We have a ton of investment opportunities and growth ahead in our compression space. We’re excited about investing there right now. That’s where we expect to deploy both our capital and keep our focus in the strategically as we look out into the market today.

Operator: Our last question today will come from Elvira Scotto from RBC Capital Markets.

Elvira Scotto: Can you talk about what you’re seeing in basins other than the Permian? If you’ve seen any growth as a percentage of your fleet going to some of these other basins? How you see that evolving in the medium and longer term, especially as we see an increase in LNG export capacity? Then does that change any pricing or cost or economic dynamics?

D. Childers: Thanks, Elvira. 60% of our growth is still tied to the Permian. We think 60% of our growth going forward is likely to remain tied to the Permian, and it could go actually higher. Remember, that’s really driven by just the breakeven costs and the lower cost of the producers to move oil and gas in the Permian, so that’s number one. We have seen bookings and incremental growth in other basins, including the Haynesville, the Rockies and in the Northeast in the Marcellus. Those basins are absolutely being reactivated. We haven’t seen reactivation of dry gas basins, significant reactivation in dry gas basins beyond those, but in those basins, we have seen incremental growth, but the Permian remains the inexhaustible and focus for the energy industry right now.

As far as will that change some of the dynamics in the industry? Pricing, hard to see that changing even if we see equipment and infrastructure moving into other plays, given the high levels of utilization, those plays have to compete on a CapEx allocation level to take that capital away from the Permian and put it in other plays. I do believe that the returns that we’re going to achieve in other plays have to be comparable to what we’re achieving — the industry is achieving in the Permian to attract CapEx away. Finally, I think that to support LNG expansion, we do think that Eagle Ford, not dry gas, but Eagle Ford Shell will also see a growth resurgence and that the LNG export should really be mostly supported by the Haynesville, Permian and Eagle Ford going forward, but the Northeast is going to require for data center demand and power demand, in particular, some growth ahead as well, and that’s going to require some compression.

That’s the way we see how this is shaking out in other plays and how some of the dynamics could be impacted.

Elvira Scotto: I think in your prepared remarks, you noted that you’d finance the CapEx through internally generated cash flow and some potential asset sales. If you look across your portfolio, what is the potential for asset sales?

D. Childers: Thank you for the question. I think this is an area that’s underappreciated in the dynamic of our business and how we run it today. When I look over the past 5 years, our asset sales on — for 5 years have averaged more than $95 million per year. If I look back 5 years before that, our asset sales averaged still north of $40 million a year. In other words, when you have a fleet business the way, like we have, to keep it fresh and competitive and moving both through customers, through basins, through generations of equipment, having a prudent approach to asset sales is really critical to the business. I think you can snap the chalk line by saying in the low end is somewhere in that $40 million range and the higher end is more in the $90 million range with some variation off of both of those, but that’s a way of thinking about how we attend to keeping our fleet as young and as competitive as we can keep it.

Elvira Scotto: If I can sneak in one more. You mentioned that lead times for the Cat engines are about 60 weeks. How does that compare to maybe where it was 3 months ago or 6 months ago?

D. Childers: I’m not sure I can keep track of all those time frames, Elvira, but 6 months ago, I think we were more in the 42-week time frame, and we’ve seen that increase out. That’s the best collection I can offer on those time frames.

Operator: There are no more questions. Now I’d like to turn the call back over to Mr. Childers for final remarks.

D. Childers: Great. Thank you, everyone, for participating in our Q3 2025 earnings call. I look forward to updating you on our progress next quarter. Thank you.

Operator: This concludes today’s conference call. Thank you for your participation. You may now disconnect.