How data center growth is slowing the US shale comeback

**Let's Talk Energy — Episode 41 ** How data center growth is slowing the US shale comeback, with Ryan Hassler and Marauder Capital's Roe Patterson Wednesday, 10 June 2026 SPEAKERS **NB** Noah Brenner — Host, Let's Talk Energy **RH** Ryan Hassler — Product Manager, North American Cost and Prices Solution, Rystad Energy **RP** Roe Patterson — Managing Partner, Marauder Capital [00:00] NB This is Let's Talk Energy, your go-to podcast for smart energy insights. I'm Noah Brenner. Oil and gas companies working onshore in the US are cautiously increasing activity in an effort to bring on more production, incentivised by the currently high prices for oil. While the price outlook remains highly fluid, the continued conflict in the Middle East, alongside the need to refill the resulting 1 billion barrel deficit in global storage levels, is giving CEOs the confidence to marginally increase production. NB But as many listeners know, oil companies themselves don't drill wells or hook them into pipelines or work over existing wellbores or do any of the things that are needed to get more oil and gas to flow out of the ground. They pay oilfield services companies to do that work. So how much more equipment might be needed in the market to meet the projected demand from US shale players? What are the pinch points that could limit the ability of oilfield service companies — or make it more expensive for operators to ramp up production? And how have changes in the sector, including past consolidation and the ongoing diversification into work outside the oil and gas industry such as data centres and the power supply needed to fuel them, changed dynamics in the market? NB To give us a deeper understanding of the state of the US onshore oilfield services sector, we're joined today from Denver by Ryan Hassler, the product manager for Rystad Energy's North American Cost and Prices Solution. Ryan, welcome to the programme. RH Thanks for having me, Noah. NB And from Fort Worth, we're joined by Roe Patterson, the managing partner at Marauder Capital and the founder and chairman of Clearwell Dynamics and Ventana Midstream. Roe, great to have you with us. RP It's great to be here, I appreciate it. NB Well, let's talk energy, gentlemen. Roe, I think most listeners are probably familiar with Rystad Energy at this point. Some may not be as familiar with Marauder Capital and some of the other companies that you're involved with. Give us a quick snapshot of what you're doing at Marauder and how you got there. RP I've got 30-plus years in the industry, all on the services side of the oil and gas sector. After I retired as a public company CEO, I was looking for the next phase of what I wanted to do and was finding a lot of opportunities to invest in companies that I knew I could buy below their intrinsic value. So we started doing that in sort of an unsponsored fund kind of manner — private capital, my capital, friends and family, et cetera. But the more I did it, the more opportunities we found. RP One of my ex-associates from my public company days and I got to talking and I said, hey, I think this is real fertile ground for a private equity fund that's dedicated just to services and specifically production services — past the frack, after the frack. And my partner and I, Adam Hurley, agreed. And in 2024, we founded Marauder Capital to do just that. That's what we've been doing for the last couple of years and it's been a good run. We've found a lot of good opportunities to help teams, invest wisely for our LPs and for ourselves, and to coach rather than to be the quarterback. NB Thanks, really happy to have you with us to bring that perspective. Ryan, at the top of the programme I mentioned that US onshore companies are looking to grow production marginally. Here at Rystad, we've upped our outlook for US oil output by about 500,000 barrels per day this year to roughly 14 million barrels per day, and we see further growth next year of maybe another half million barrels per day. What are we anticipating in terms of the increased need for equipment to meet that type of growth, and which operators might be driving some of that activity? RH With that call of increased demand from the operators, we're seeing a maximum of around 30 additional horizontal rigs by the end of this year. That's a little bit biased towards the Permian, but more broadly oil basins, obviously, as this translates to a much higher oil price environment. And that 30-rig addition would also be chased by anywhere between 10 to 12 frac fleets on the pressure pumping side. This is the supplier's equipment response to the movement that we see from those upstream shale producers. There's not really been an immediate response, and compared to previous cycles, with a price signal this high, the response is somewhat muted. [04:00] RH From the operator's perspective, we have seen announcements in the public space already from Continental, Diamondback, ConocoPhillips, and a few others where we already have visibility into around 10 to 15 of those additional rig adds. So while we're in a much more consolidated upstream environment this time around, largely the increase is being announced from public operators today. The remaining 10 to 15 rigs that we're calling for on that upper limit of 30 could be brought into the market still by private operators — just certainly not to the extent that we saw a big private ramp-up like we did in 2022. Overall, upwards of 30 additional rigs on the drilling side and maybe between 10 to 12 on the pressure pumping side from a frac fleet addition standpoint. NB Roe, how do things look from your side? You mentioned you're firmly on the production side of the services space. What are the types of inbound calls that you're seeing, and does it support this kind of modest increase in activity? RP Most of what we've seen is really an increase in volumes based on capex budgets that were set in 2024 and 2025. We haven't seen a flood of capex come back to the market based just on the price escalation from the war. Most of our customers have been pretty much trying to keep one foot on the gas, one foot on the brake — stick with their return capital to shareholders mandate, not get over-levered and not chase too much growth. Live within cashflow, et cetera. RP On the production services side, that has been manifested through enhanced recovery of existing assets and acquired assets through acquisition, as a lot of our customers have merged. There's a large focus on not only maintaining production but enhancing production with new types of artificial lift. There's a lot of demand around in-basin power — the grid itself cannot really meet the demand needed for artificial lift within these newer developing basins at the scale that's needed. So we see a lot of remote power, a lot of movement in gas compression. Obviously, you can't move the barrels without moving the gas. There's also some gas compression tied to enhanced recovery through gas lift. And then water — water is still an issue that a lot of our customers have to focus on. If they can't move the water, they can't move the hydrocarbon. That's really driving a lot of demand in production services — finding the most efficient way to deal with existing assets, and then augmenting that with secondary and tertiary recovery programmes. [08:00] NB Both of you mentioned price in your responses. Oil is bumping around $100 today. We've seen wild swings — some of the highest in history — due to the back and forth over the war in Iran and how it might resolve itself. What's the feeling out there as to whether this uptick in price is sustainable? Is hedging by operators making them able to lock in some cashflow and maybe be a bit more confident? What are you hearing in terms of how operators are thinking about the sustainability of the upcycle and how they might be responding to it? Roe, let's start with you and then we'll go to Ryan. RP Balance sheets are better in this cycle probably than any other cycle in my career. The leverage ratios are in very healthy positions — that's not always been the case during big swings in cyclicality. There's really no desire to raise a lot of equity dry powder or big tranches of debt. We haven't seen that this time around. That has happened in previous cycles when you've seen a hydrocarbon price spike and then everybody levers up and tries to meet the demand for growth, whether on the upstream operator side or the service side. That hasn't happened. So I think there's been what I would call a healthy response to the demand that's there. RP The confidence in oil prices today is pretty weak. Most people think it's momentary. We saw prices go from $100 to $87 a barrel in the last couple of days — that's what everyone was expecting to happen. If a firm peace agreement is made and the strait is wide open and moving, I think you'll see prices migrate lower. I will say though that the infrastructure that's been damaged because of the war is significant and it's going to play a big part in what we see from the supply side macro going forward. We've also drained inventories globally — we had another huge SPR draw this week, around 9 million barrels. We've got low inventories and I think that's going to manifest itself in the overall macro going forward. As far as the response from the sector broadly, it's been muted, because the confidence in these wild swings to the high side — people don't think there's staying power there. RH The change in price we've seen over the last two days in WTI had been a major signal in the first three months of this conflict, where operators had really been looking to the tail end of the futures curve — six to nine to twelve months down the line — to see if there was any confidence in that shape of the curve with a number of around $80 per barrel where we've been hanging our hat. There's been a tone of caution, reinforced through the cyclicality of the conflict. We did see a little bit of a more sustained signal around that $80 per barrel price mark in the nine-to-twelve-month range for maybe a few weeks, and that did coincide with a few announcements on the public side of a couple of rigs being brought back. But we're now back below that $80 mark, and the confidence is weak. Operators have been reinforcing that cautious tone and capital discipline. We're in an environment where hedging contracts have improved marginally, and many operators are happy just cash-harvesting in the open market. It's really a question of confidence in the tail end of that price curve, and that's what's been holding up a quicker or more sustained response from the upstream side. [12:00] RP Our businesses were relatively healthy and busy at $60 a barrel before the war ever started. And I think that's significant because lifting costs were in an appropriate range for the amount of capital deployment we were seeing from the upstream E&P operators — they were still comfortable with the margins they were making. That tells you something: even if prices migrate back below $80, you're still going to see healthy levels of activity. On the gas market, the strip is closely watched and it's very bullish — gas pricing because of LNG demand, data centre demand, power demand, et cetera, and the role that natural gas will play in all of that. We're seeing healthier strips there and a lot of confidence around the strip. NB Ryan, you mentioned some numbers in terms of rigs and frac spreads that might be needed. Is there enough idle capacity in the system to meet those numbers, or which areas could be potentially tight? RH On the drilling side — if you think back to the last 12 to 18 months, the drilling count has continually declined over that period. That's not a long enough stretch where a lot of that sidelined equipment has really atrophied. It can come back into the market relatively easily — it's just a matter of the cost of reactivating it. Within that threshold of around 30 rigs, there's relatively little cost to reactivation compared to previous cycles — anywhere between $500,000 on the lowest end to upwards of a million within that first 20 to 30 rig reactivations. Every incremental rig beyond that 30 will of course cost a little bit more. On the drilling side, there is equipment availability — it's just a matter of how much it's going to cost to bring it back. RH On the completion side, it is a little bit of a different story. In short, yes, there is enough idle capacity from a pressure pumping standpoint, but the way the market has shaped itself over the last 12 to 18 months is a little different. We've seen more consolidation from the pumpers. And the rise in continuous pumping operations — simul-frac and tri-frac — has led to a lot of equipment being brought in for redundancy on those continuous pumping pads. Upwards of 20 to 30% additional horsepower is required. That's created a real tightness that didn't exist prior to the rise in adoption of continuous operations. Operators who have been employing continuous pumping operations are not readily going to want to break up those crews to allow those pressure pumpers to chase incremental work in the spot market. That means you're going to have to reactivate more equipment than would otherwise have been needed. [16:00] RH There is equipment availability — it's a matter of engine type and which equipment is going to be brought back into the market. And because of the price of diesel today, there's much more incentive for natural gas-capable, dual-fuel, dual-gas blending equipment to be brought back, which creates a little more of a price signal for that specific category. So there's a little bit more of a costly reactivation on the pumping side. But in short, there is still enough capacity to meet the demand signal we're calling for. NB How difficult might it be to bring the people back to work the equipment? RP It's always difficult to bring labour back to the sector. It takes time, requires a lot of training. A number of people have left the market as activity shrunk a little bit, and bringing back that talent costs money. Wages usually have to go up, which means costs go up, which means rates go up, and it takes time. The technological improvements we've made — in not only the way we frack but the equipment we use, directional drilling, et cetera — those things require even more training, because the technological jumps have been significant. You're not coming back to do the job you did two years ago; you're coming back to do a slightly different job with different types of technology. So there's a lot of training involved, and that's just a time thing and a money thing. RP We as a sector are typically able to attract talent back at the end of these cycles. The capability is there. One thing that's a little different this time around is the power piece — that's sucking a lot of labour out of the market, because technicians and mechanics and all of the people who operate that equipment have opportunities within the power space. And some of our frackers are now investing in power and making pretty significant returns on capital from those power investments. So if they're balancing — do I bring back a Tier 2 frac fleet because of demand and I'm going to have a return on capital that's X, but if I spend my capital on power I'm getting X-plus-plus — they're going to bring the power on, and the frac may take a back seat. We'll have to see how that dynamic plays out, because it's different this time around both in terms of labour and in terms of the economic opportunities that a lot of these companies are facing. NB Is this the first time we've really had a competition where companies had an alternative to the oil field that maybe was a higher return rather than just having to fight over labour? RH It is real. And maybe it's not the first time there's been competition from other industries, but for the pressure pumpers specifically, there has been a real emphasis on the power side of their business. That side of the business has been seen favourably by the investment community — more so than the cyclicality of the oilfield services industry, which hasn't been seen all that favourably recently. Roe made the point of what's the incentive for a pressure pumper to bring back some of this legacy equipment into the market — we're not seeing that big of a demand signal. It's really 10 to 12 additional fleets, and while that maybe doesn't exist in its entirety right now, it is capacity that's available. That equipment could be put to work in this competing industry and maybe see a more favourable return. So then it becomes a question of what kind of inflation are we going to see from the upstream side, what kind of service price inflation will we expect to see — and it's always coming down to a price point. It's just a matter of where the demand is coming from more strongly. [20:00] NB Does the changing shape of the sector make it respond differently to the call on equipment? RP The short answer is no. Service companies are always going to take the talking point that they're holding out for margin versus utilisation. They never do — the bait is too strong and too powerful to not try to jump on increased utilisation of your existing fleet and chase operating leverage where you can. I do think there's less of a drive for pure scale, because scale didn't pay dividends in the past. The service companies are smart and they've figured out that they have to return to shareholders as well — and they do that best through operating leverage, efficiency improvements, and investing in the highest-margin businesses. But I always see companies migrate back to: if I can figure out a way to put one more piece of equipment out, I'm going to try to do that. And if the demand is strong enough, they will do that again, whether the margins are the overall attraction or not. RP I do think the balance sheets are in better shape on the service side as well. One thing that's missing this time around is private capital — heavy private capital investment, especially on the completion side. It was popular just five years ago to have a private equity fund investing in services, but some got burned or made marginal returns and haven't come back to the space. Things would have to get pretty frothy for them to come back. So we're also seeing a lack of commercial debt and leverage available, and a hesitancy to get over-levered to meet any kind of growth demand. People are going to be careful and hesitant — they're going to want contract coverage, take-or-pay coverage. Whether the upstream E&P operators are willing to make the bet and sign some pretty teethy contracts to get the capacity they need — we'll see how that plays out. RH We are in a much more consolidated oilfield services space than we have been previously, so that may lend itself a little better to some margin capture rather than market share capture. But especially on the completion side, it is a very fragmented business historically with very low barriers to entry. The signal I would look for is how sustained is this demand beyond 2026? If we're talking about a more significant demand signal in 2027, then you get into the sort of problem we've seen in previous cycles — with those low barriers to entry and equipment availability that can be bought at auction and brought back relatively easily, you start to get into a position where there's more market share capture and cost competitiveness that erodes into margins. That's maybe a longer-term signal if this demand stays structurally supportive through 2027. Looking back on previous cycles, you can see how low those barriers to entry are and how that increases the competitive landscape quite quickly and quite dramatically. [24:00] NB It sounds like we're not talking about actual shortages that are going to limit production. But we have mentioned inflation a couple of times. What are you forecasting in terms of the potential for general onshore OFS inflation? RH Broadly, what we're forecasting for core drilling and completion categories is between 7% to 10% inflation from the bottom of Q4 2025. There was a little bit of softness in the first couple of months prior to the war — January and February — where pricing either continued to slide or held pretty much flat to Q4 2025. But doing exit-to-exit, Q4 2025 to Q4 2026, we're calling for around 7% to 10% inflation. There are some caveats — on the completion side there's maybe a little more structural tightness, so the upside risk to slightly more inflation for pressure pumping is a little more outsized than on the drilling contractor side. RH There are other categories we haven't really talked about yet that have been driving a little bit of inflation already — things like workover rigs. Roe talked about compression, which hasn't really seen a cooldown in the last few years anyway, and that inflation just continues to grow through the end of the decade. On the workover side, operators are trying to squeeze every additional barrel they can without having to reactivate new equipment, and we've been hearing reports already of 7 to upwards of 10% inflation there as well. Diesel surcharges were originally quite difficult for suppliers to push through, but that pushback has pretty much fallen away now — and that contributes to around 2% inflation on well costs just at a baseline level. Overall, the main takeaway is maybe upwards of 10% with some additional upside risk on the pressure pumping side, and some inflation on the workover space as well. NB If you're able to pass through diesel costs or fuel costs more readily, does that actually mean this inflation translates into a better margin for OFS companies — or does it get eaten up? RP Ryan's numbers are spot on for what I've seen broadly across all segments. The surcharges for fuel — if prices come down, operators are going to ask for that back. So typically what service companies do is try to tack on some incremental margin for themselves and hold onto it as best they can while giving away some of the fuel surcharges. But overall, inflation is a real number and we're going to see it. It's not just labour inflation, which is real — we've seen parts inflation, inflation in all of our consumable expenses: motor oil, hydraulic fluid, all of the rubber goods we use in the business that tend to flow through the ticketing process. Those prices are up somewhere in the neighbourhood of 10 to 15%, even as high as 20% in some cases. Service contractors are trying to push that through to the end user and we're seeing less pushback right now. RP If prices migrate down, there will be pushback. But these inflationary expense numbers aren't going away. Pretty much every component that we use — solenoids bought overseas, parts manufactured domestically for replacement components — they're still more expensive today than they were a year or two years ago. The inflation is sticky. It rarely comes away. I do think Ryan's number of somewhere in the 7% to 10% range is going to happen and those numbers are going to stick. They're going to have to stick, because even today most service companies are not making replacement cost economics or new-build economics for their return on capital. The operators are going to have to figure out that if they want these service companies to keep providing services at a very high level and want efficiency improvements to maintain themselves, they're going to have to allow these companies to make enough margin to replace equipment and to do new builds at some point. [28:00] NB What's driving the cost increases in parts and components? Is this a tariff issue, or are the companies making those bits and pieces diversifying into other more lucrative businesses like data centres? RP Tariffs have played a role, and the fear of tariffs has played a significant role. But you also have competing demand for components across different subsectors of all industries. Microchips, just as an example — we are using a lot of microchips on all of our engines and telemetry equipment, whether you're in compression, power generation, or fracking. We're competing for the same microchips that everyone else in the broader industry is using. So the answer is competition between other industries and segments, tariffs, and just overall global inflation — all playing a role in the higher cost of replacement components, parts, and pieces, and that feeds through to new-build costs as well. NB Is this a good time for the industry to consolidate? Will we see some mergers driven by the environment we see today, or is it more likely that companies wait, or choose to stay at the size they're at? RH In the oilfield services space, I do believe there's never a bad time for consolidation, because of how fragmented that space is. Building some of that scale, or at least some supply consolidation, can generally lead to better pricing and better market utilisation and capture of those margins. But we're in a fairly consolidated market already for the drilling contractors, which have historically been more consolidated, and on the pressure pumping side. If we zoom into some of the more niche categories — proppant, the in-basin frac sand space — that's the market I have my eye on. It's a very fragmented space, particularly in the Permian, with a lot of individual sand mines that have logistical or geographical advantages for specific smaller subsets of operators. Prior to the war, we were seeing really low pricing, right at or below operational costs for many of the sand suppliers — margin erosion was real there. This conflict and the increase in demand is extending a bit of a lifeline to the in-basin sand supply space in the Permian, and that was a market that definitely could have used some consolidation. [32:00] RH Across a lot of these categories — proppant, frac, drilling — what's the incentive for consolidation right now? I do think there are opportunities for more consolidation, but the incentive and return on that consolidation right now, I'm not sure it's well aligned with where a lot of these companies are trying to strategically move. The skepticism from the upstream community around this price signal and the amount of demand it's going to spur is shared in the oilfield services community. If you don't truly believe that in 12 months we're still going to be in this price environment with healthy demand, why would you spend that capital now when you could be moving towards a down cycle in a short period of time? Having said all of that, I still wouldn't be surprised if there is some level of consolidation that does take place over the next six to nine months. RP I just don't think scale is going to be one of the primary drivers. All the drivers that Ryan mentioned are going to be more of the things that drive whatever consolidation we do see. Is it time to consolidate in a lot of these subsegments that are extraordinarily fragmented? Absolutely. Do we need to see more consolidation? Absolutely. That's a harder thing to make happen than it is to say. Whenever stock-for-stock transactions take place, the seller has to get aggressive enough to make the buyer want to do the transaction, and those are hard things to make happen. Can it happen and will it happen? I think it will. Doing it with leverage is going to be frowned upon by the investment community. Anytime you can do a cashless transaction, people are going to be more excited. Smart transactions will get rewarded — growth for growth's sake probably won't. Ryan's read on the investment community is absolutely accurate — they're cautious and they don't want to see any unbridled growth that comes with high leverage risk. Those dividends that both E&P companies and contractors have put in place, investors like those dividends and they don't want to see them go away. So I think it's going to have to be smart transactions. Is it needed? Are there opportunities? Absolutely — that's why we're all in the business. I'm excited about the opportunity for consolidation, always have been. They're just hard to do. And I think the drivers are different today than they've ever been. [36:00] NB What's the one thing you think is important for listeners to take away from this? Roe, let's start with you and then we'll go to Ryan. RP One thing to take away is that the war really hasn't changed a ton of the macro dynamics within the industry. The industry was fairly healthy before the war — it's healthy now. A lot of the talking points within the US administration about drill, baby, drill — none of that has really happened since Trump's inauguration. In fact, they've probably taken some steps to go the other way. So despite all of that, business was in very good shape before the war and it's still in good shape. I think there's a lot of bullishness around natural gas for a lot of different reasons, and oil is always going to be the tip of the spear. We've seen a lot of steadiness and conviction to maintain good capital discipline on the part of the US E&P group, and I think that's going to continue. RP They're still going to be out there searching for new inventory — globally as well as domestically. Some of the inroads we've seen from US producers in Argentina are a very good example of guys looking for good reserves and good opportunities for growth. All of that was happening prior to the war. As things settle down — hopefully this thing ends, the strait opens up, and we see prices get some solid stability behind them — I think it's going to be a healthy cycle for the business for the next 12 to 24 months. The business is in a very healthy spot, balance sheets are in a healthy spot. I'd love to see some consolidation and I think there will be some. But I don't think we're going to see any spikes in activity based on these global dynamics from the war. RH My closing argument here is a little bit more cautionary. And I do agree with everything Roe just said. We're in an environment today with this price signal that operators are responding to a lot differently than we've seen in previous years from US shale producers — that caution and capital discipline is reinforced. But my takeaway is that we were in a market that prior to the conflict was structurally oversupplied if we think about the global oil market. And we're now in a position where we're potentially adding barrels into a market that three months ago didn't need any additional barrels. There are structural damages to infrastructure that have certainly happened and will create a bit of a buffer for some of this additional capacity coming back. But having seen so many of these cycles, I know that as we add supply into a market that didn't necessarily need it, we potentially go into another down cycle that hits the oilfield services space a lot more than it does the upstream space. [40:00] RH I don't think we're going to see something like previous cycles with a price signal this significant, again because of the capital discipline and caution we're seeing from the upstream space. But it is a tone of caution that we've been hearing in conversations with a lot of our clients — around the fact that perhaps we don't need to be adding barrels into this market. And once the Strait of Hormuz reopens and flows normalise, there will be a period where some of that supply hits a market that's not buffered as well as it was previously. The main takeaway is to reinforce that caution and make sure we don't put ourselves in a position that the industry has in many of these previous cycles. NB Certainly the industry appears cautious. Should operators want to ramp up, they're going to need to compete for labour and equipment and attention from an industry that is now also looking at opportunities in data centres and power — both of which are booming right now and have a very rateable runway to growth. That means they might need to pay a little bit more. But there could be some relief from that inflation should we see the type of oil price response that could happen if the war in Iran is wrapped up. And perhaps there's plenty of equipment already in the market if oil prices don't maintain this higher level. Gentlemen, I want to thank both of you. Roe, thank you for joining us. RP Absolutely, it was a pleasure to be here. NB And Ryan, thanks for making the time. RH Yeah, you bet. Great talking to you guys. NB Thanks for listening to Let's Talk Energy. This podcast is a Rystad Energy production, produced by Elliot Busby and Bade Og. Check out the show notes for further analysis on the topics we've discussed in the episode and find us on social media — we're at Rystad Energy on all major platforms. While you're there, leave us a review, subscribe, and hit that like button. You can also keep up to date on our website. 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