Atlas Energy Solutions Inc. (NYSE:AESI) Q4 2025 Earnings Call Transcript

Atlas Energy Solutions Inc. (NYSE:AESI) Q4 2025 Earnings Call Transcript February 24, 2026

Operator: Greetings, and welcome to Atlas Energy Solutions, Inc. Fourth Quarter and Year-End 2025 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Kyle Turlington, VP, Investor Relations. Thank you. You may begin.

Kyle Turlington: Hello, and welcome to the Atlas Energy Solutions conference call and webcast for the Fourth Quarter of 2025. With us today are John Turner, President and CEO; Blake McCarthy, CFO; Tim Ondrak, President of Power; and Bud Brigham, Executive Chairman. John, Blake and Bud will be sharing their comments on the company’s operational and financial performance for the fourth quarter of 2025, after which we will open the call for Q&A. Before we begin our prepared remarks, I would like to remind everyone that this call will include forward-looking statements as defined under the U.S. securities laws. Such statements are based on the current information and management’s expectations as of this statement and are not guarantees of future performance.

Forward-looking statements involve certain risks, uncertainties, and assumptions that are difficult to predict. As such, our actual outcomes and results could differ materially. You can learn more about these risks in the annual report on Form 10-K we will file with the SEC on February 24, 2026, our quarterly reports on Form 10-Q and current reports on Form 8-K, and our other SEC filings. You should not place undue reliance on forward-looking statements, and we undertake no obligation to update these forward-looking statements. We will also make reference to certain non-GAAP financial measures such as adjusted EBITDA, adjusted free cash flow, and other operating metrics and statistics. You will find the GAAP reconciliation comments and calculations in yesterday’s press release.

With that said, I will turn the call over to John Turner.

John Turner: Thank you, Kyle. For the fourth quarter, Atlas generated $36.7 million of adjusted EBITDA on $249 million of revenue, representing a 15% adjusted EBITDA margin. For the full year 2025, we delivered $221.7 million of adjusted EBITDA on $1.1 billion of revenue, achieving a 20% adjusted EBITDA margin. Our Q4 results exceeded our initial expectations. Volumes came in at 5.3 million tons, flat sequentially with the third quarter. The typical end of year seasonality was notably muted as customers took minimal downtime around the holidays. This was particularly encouraging following the steep decline in West Texas completion activity we experienced over the summer. It now appears that most operators have adjusted their activity levels to align with the $50 to $60 WTI strip and are comfortable maintaining operations at these levels.

The quarter also marked the highest utilization we’ve seen to date on the Dune Express as Delaware Basin customers increasingly recognize the efficiency and reliability benefits of this system brings to their logistics supply chains. We view this as a strong indicator of the system’s performance heading into 2026. In November, we announced the order of 240 megawatts of power generation equipment, accelerating our strategic evolution into a leading provider of behind-the-meter long-term power solutions across a broad range of domestic industries. We see the evolving power market over the next decade as a truly generational opportunity, and we’re moving aggressively to capitalize on it. After years of relatively flat U.S. electricity consumption, the grid is now confronting surging demand, which hit record levels in 2025 and is projected to grow by as much as 25% by 2030, driven by the explosive expansion of data centers and the resurgence in domestic manufacturing.

Utilities are struggling to keep pace amid infrastructure constraints and reliability challenges where rising residential electricity prices up 7.4% in 2025 alone are creating political and economic pressure for more affordable, dependable alternatives. This dynamic is pushing developers to secure dedicated behind-the-meter power assets to derisk their projects and meet time lines. For many of these companies, grid constraints represent a new and urgent challenge, compressing decision-making windows dramatically. Since the summer of 2024, Atlas has been positioning itself as the go-to solution in this space. The Moser acquisition completed this time last year provided a cash flow platform and critical engineering expertise that complements our strength in large-scale project execution.

Over the past 9 months, we’ve been actively transitioning the business from a traditional short-term generator rental model to a power-as-a-service approach, selling electrons under longer-term arrangements. This shift has involved upgrading communication systems, refining our sales process and focusing our commercial efforts towards customers seeking dense long-term deployments. We’re encouraged by the progress. We reached a tipping point in this transformation. Earlier this year, we successfully deployed our first microgrid with the Permian E&P customer, which has since been upsized. In the first quarter of 2026 alone, we anticipate deploying at least 30 megawatts under long-term microgrid multi-basin contracts with E&P and midstream customers.

Based on our current pipeline, we are targeting more than 50% of our existing fleet under long-term contracts by year-end. January also marked the initial deployment of our patented hybrid battery solution, which integrates with generators as a grid-forming system, delivering meaningful improvements in cost and maintenance efficiency. The commercial potential for this technology extends far beyond the oilfield. While these advancements in our existing power business are promising, the larger behind-the-meter projects represents a true step change opportunity for Atlas. We have active commercial negotiations underway and expect to provide greater visibility on equipment placement and the resulting economic impact to Atlas in the near term. Our pipeline features a broad range of behind-the-meter power projects across multiple industries, including energy, data centers, manufacturing and others, with contract terms typically spanning 5 to 15 years, creating durable long-term cash flows.

We have particular strength and see especially compelling risk-adjusted returns in projects in the 50 to 500-megawatt range where our modular platform enables efficient execution and high-density deployments. At the same time, our differentiated track record with large CapEx infrastructure projects such as our high-capacity plants and the Dune Express conveyor system, combined with our scalable design and growing expertise advantage us for the execution of even larger scale opportunities as customer demand intensifies. The opportunity set continues to expand rapidly with several prospects advancing from initial discussions to formal proposals and active negotiations. We are targeting more than 500 megawatts deployed across our fleet in 2027 with the potential for substantial additional growth beyond that as we secure larger scale projects and build on our initial orders.

The ordered equipment is slated for delivery starting in the second half of 2026 with energization targeted to begin in Q1 2027. Each of these projects has the potential to meaningfully enhance Atlas’ cash flow profile, and I am very excited to share more details with you as we close transactions. So stay tuned for the updates. I will now turn the call over to our CFO, Blake McCarthy, through our financials in more detail.

Blake McCarthy: Thanks, John. The underlying performance in our sand and logistics business improved in the fourth quarter despite a continued challenging pricing environment. Plant operating expense per ton declined sequentially to $12.28 despite elevated costs in October related to the operational challenges in Q3 and higher maintenance spending during December. Our cost of production, although improved, remain elevated at our flagship Kermit complex due to current limitations on our dredge feed. This is expected to be alleviated with the deployment of our 2 new Twinkle dredges, which are scheduled for commissioning in the second quarter. The market backdrop for West Texas sand and logistics remains challenging with current pricing at the industry’s marginal cost of production.

Permian completion activity is expected to be down year-over-year, although it appears to have stabilized at Q4 levels for now. Despite the challenging market environment, Atlas’ commercial team has positioned us well to grow volumes in 2026. Leaning on our cost-advantaged mines and logistics network, we were able to increase our share of current customer sand procurement spend while also adding some key new customers, relationships we expect to grow and scale over the course of 2026 and beyond. The current oil macro environment remains quite opaque. So we don’t have significant visibility into all of our customers’ full year plans, but our Q1 schedule is very busy with sales volume expected to be up approximately 10% sequentially and further growth expected in the second quarter.

The winter storm at the end of January impacted everyone’s operations in the Permian, and we lost approximately 4 days of production and deliveries. This temporary shutdown is expected to negatively impact Q1 EBITDA by approximately $6 million. However, I’m proud to say Atlas was the last sand provider delivering in the Delaware before we had to shut down due to ice. The fact that was made possible by the Dune Express, removing so much road mileage and the related risks. Speaking of the Dune Express, it continues to run extremely well. January 12 marked the 1-year anniversary of its first commercial delivery. And thanks to our partners, I’m proud to announce that we have eliminated more than 21 million miles of truck traffic in the Delaware Basin.

We are very proud of the fact that the Dune Express is materially improving quality of life and safety for families and the broader community in the region. The Dune Express achieved record shipments in the fourth quarter of approximately 2.1 million tons, including a monthly shipment record in November of 760,000 tons. For the first quarter, we expect new customer wins and continued spot volumes to drive improvements in Dune Express volumes and believe we are positioned to deliver north of 10 million tons via the Dune Express this year. We are grateful to our customers for partnering with us to make the Permian Basin a safer place to live and work. All that said, the obvious question is, if the Dune Express is working so well, why were Q4 service margins so weak?

While Q4 numbers were burdened by large load bonuses to ensure driver availability through the holidays, the real answer to that question is simply pricing. Logistics pricing in the Permian has fallen to completely unsustainable levels, well below those seen during COVID. To compete with the Dune Express, we have seen increasingly irrational behavior from some of our logistics competitors, which we believe sets both them and their customers up for eventual problems and disruptions. We believe several companies are currently delivering standard prices where they’re effectively subsidizing their customers. Thus, the margin differential provided by the Dune Express is there. It’s just partially insulating us from historically bad pricing. Encouragingly, we are seeing signs of this market beginning to break the other way.

Third-party trucking rates are beginning to see upward momentum, echoing what we’re seeing in the broader over-the-road market. That is typically the first sign that trucking companies are tired of subsidizing their customers, and as a result, margins have to come up. In November, Atlas introduced our first last mile storage pile system to the market. While other pile systems in the market essentially use mining equipment that has been reapplied for the oilfield, our system is built for purpose. Today, we have 6 systems in place to support our wet sand operations with testing underway for deploying the system in dry sand operations. These systems are key to continuing our further enabling of our customers’ continuous pumping initiatives, which are driving record sand consumption per completion crew.

While the market for sand and logistics in 2026 looks like it will remain challenging, we are looking to take advantage of the weaker market conditions to cement Atlas’s position as the provider of choice. The pricing pendulum in our industry has swung too far for too long, and the pricing over vantage is certainly tight. We’re hearing more anecdotes of competitors struggling to fill customer obligations. And I’ll echo the comments from the large-cap oilfield services calls when I say that it’s only going to take a very small increase in completions activity for pricing to move. This RFP season, we saw market share shift to the higher-quality suppliers with fewer volumes being spread amongst the lower-quality mines. The supply/demand for sand in the Permian is much tighter than the market realizes, especially for dry sand.

On our last conference call, we set a cost savings target of $20 million in annualized savings. As it stands today, we have executed upon that target through a combination of the elimination of third-party last mile equipment, reductions in rental equipment, headcount optimization and procurement savings. Despite the early success of these efforts, we will continue to push for further cost optimization as we look to lower the fixed cost structure of our business across the organization. Moving to our financials. As John touched on earlier, Atlas recorded full year 2025 revenue of $1.1 billion. Total company adjusted EBITDA was $221.7 million or 20% of revenue. Deconstructing full year revenues, proppant sales totaled $478 million on volumes of 21.6 million tons, while logistics and power contributed $558.8 million and $58.5 million, respectively.

Fourth quarter 2025 revenue of $249.4 million broke down to the following: Proppant sales totaled $105.2 million, Logistics contributed $126.1 million and power rentals added $18.1 million. Total proppant sales volume was slightly up sequentially to 5.3 million tons, while the logistics business delivered approximately 4.9 million tons. Our average sales price for the fourth quarter was approximately $19.85 per ton. For the first quarter, we expect volumes to be up approximately 10% sequentially with the average sales price of sand to be approximately $18 per ton. Q4 cost of sales, excluding DD&A, were $187.3 million, consisting of $60.6 million in plant operating costs, $115.2 million of service costs, $7 million in rental costs and $4.5 million in royalties.

For the fourth quarter, our per ton plant operating costs were approximately $12.28, including royalties, down sequentially from the third quarter, but still elevated versus our normalized levels. Higher volumes and a reduction in extraneous costs at the plants for Q3 levels drove the lower plant operating costs. For the first quarter, we expect our OpEx per ton to be approximately in line with the levels in the fourth quarter, reflecting the impact of the severe weather in January. Over the course of 2026, we expect to see improvements in our realized variable costs as the new dredges are commissioned at our Kermit facility. Cash SG&A for the quarter was $22.6 million. SG&A, excluding litigation expenses, is expected to decline in the first quarter due to our previously announced cost-cutting initiatives.

Adjusted free cash flow, which we define as adjusted EBITDA less maintenance CapEx, was $22.9 million or 9% of revenue. Growth CapEx equated to $5.1 million, the majority of which was tied to our Power segment and maintenance CapEx during the quarter was $14.4 million. The elevated maintenance CapEx spend was primarily tied to preparations related to the dredging and wet plant operations at Kermit ahead of the Twinkle dredge deliveries. We expect cash capital spending in 2026 to be approximately $55 million, down significantly year-over-year and heavily weighted to the first half. Maintenance CapEx of approximately $45 million is planned with approximately $10 million dedicated to growth, evenly split between sand and logistics and power. Additionally, we expect to make progress payments on the 240 megawatts of power assets we have on order as they begin to be delivered over the course of the second half of the year.

These payments will be financed from our recently announced lease facility with Eldridge and are expected to total approximately $190 million over the course of the second half of the year. Net interest expense is expected to be approximately $16.5 million per quarter in the first and second quarters, rising to approximately $20.5 million in the third quarter and $22 million in the fourth quarter. As John also touched on in his remarks, our plants have begun the year quite busy with WTI prices hovering around $60, oil prices will dictate if we continue to keep this pace up. We have a clear line of sight on strong volumes for the first half of this year, but many of our customers are taking a wait-and-see approach with respect to their second half completion schedules.

Our recent market share gains are a testament to Atlas’ efforts to position ourselves as the reliable partner of choice to the best operators in the Permian Basin. For the first quarter, while volumes are expected to be up sequentially, the expected decline in sales price per ton, combined with the lost days of revenue due to the winter storm will be a headwind to margins. Additionally, our logistics business was burdened by load bonuses to ensure driver availability around the turn of the calendar, which will mute logistics margins improvement until later in the quarter. However, we are seeing a return to more normal cost structure as the quarter progresses, which combined with a growing delivery schedule, will yield an improved margin structure through the quarter.

Additionally, the power business is expected to generate a greater contribution sequentially. Thus, we expect EBITDA to be approximately flat with Q4 levels with the company exiting the quarter at a higher run rate in March versus January. I will now hand the call over to our Executive Chairman, Bud Brigham, for some closing remarks before we turn the call over for some Q&A.

Bud Brigham: Thanks, Blake. While we’re navigating another cyclical trough in oil prices, the future for Atlas has never been brighter. Just as we were ideally positioned for the post-COVID Permian recovery, which substantially expanded our cash flows, we’re primed for the inevitable rebound in oil and gas activity today. But in addition, as I stated on our last call, we’re going hybrid. Today, Atlas is laying the groundwork for transformative long-term growth through behind-the-meter power contracts. These 5- to 15-year agreements are expected to deliver robust revenue visibility paired with predictable costs, including fixed and stable expenses for SG&A, maintenance and interest, complementing our powerful but more volatile oil and gas revenue streams.

Our proven expertise in large-scale infrastructure, amplified by the Moser acquisition, uniquely equips us to power the surge in AI, robotics and manufacturing. We see these initial permanent power projects as a strategic springboard, drawing in more customers and building a portfolio of assets that generate steady recurring cash flows. As discussed by John, demand for behind-the-meter power is accelerating rapidly, fueled by rising costs and potential grid shortfalls that are pushing commercial, industrial and data center users towards swift commitments for bridge and permanent solutions. We’re witnessing a seismic shift in power sourcing. To borrow from our partners at Bloom Energy, on-site power has evolved from a last resort to a business necessity.

U.S. power demand is growing at its fastest rate in decades. Let me emphasize, the Atlas investment story is more exciting than ever. Chronic underinvestment in exploration spending, coupled with shale’s maturation and steep decline rates, sets the stage for what I believe will be a prolonged up cycle. While most U.S. shale basins struggle with inventory depletion, the Permian, where Atlas leads in proppant production and logistics will be key to meeting rising oil demand. Even at today’s cyclical lows in sand and logistics pricing, our low-cost model shines through, thanks to the Dune Express and efficient mining operations. When activity rebounds, and it’s a question of when, not if, we anticipate stronger utilization, pricing and margins, sparking a sharp profitability upturn.

By investing ahead of this oil up cycle, while we are also launching our high-potential power business, Atlas offers investors dual catalysts for substantial growth. I’m deeply grateful to our exceptional team, the true innovators fueling our advancements. Their dedication has me more optimistic than ever about Atlas’ future. Thank you for joining our fourth quarter and year-end conference call. I’ll now hand it over to the operator for Q&A.

Q&A Session

Operator: [Operator Instructions] Our first question is coming from Jim Rollyson of Raymond James.

James Rollyson: John, you talked a bit about the power side. Obviously, a quarter ago, you ordered the 240 megawatts. I’m pretty sure you mentioned then you had line of sight on customer opportunities there. You’ve since secured financing, which I presume doesn’t happen without similar line of sight. So maybe just an update on kind of what’s taken a little while on getting that contracted? And do you have good line of sight on where that equipment is actually going at this point since we’re less than a year out from its deployment?

John Turner: Yes. Great question, Jim. Thanks for asking. Yes, we do have strong visibility into the customers that are expected to take a substantial majority of this equipment package, which is on track for delivery. I think deliveries, they began at the end of late 2026 — these are high-quality creditworthy counterparties that are across diversified markets and have indicated meaningful follow-on requirements beyond their initial commitment, providing for clear pathways for additional equipment orders and sustained growth into the future. Our strategy still remains solely focused on behind-the-meter power solutions. And we’re not pursuing grid interconnected or utility scale opportunities. Instead, we are delivering reliable on-site power directly to customers facing grid constraints.

In many cases, these engagements begin with bridge power to address immediate needs, which generate significant near-term cash flow and accelerates our path to full development. These bridge arrangements quickly transition into long-term behind-the-meter agreements that we primarily are working on as customers recognize the prolonged grid time lines and value of our integrated approach. So yes, the answer to that is yes, we do have clear line of sight on who those customers are and expect to be reporting on that here shortly.

James Rollyson: Appreciate that. And maybe as a follow-up, just kind of related here is I’ve watched this market evolve and different players kind of approach this in different ways, it seems like there’s 2 strategies I’ve seen, one being guys that are just providing power equipment basically on a rental basis and then the second being guys that are providing the entire solution, all the balance of plant, et cetera. I’m kind of curious if you could elaborate on kind of which strategy fits yours and how you see the return opportunity there.

Blake McCarthy: Yes, go ahead. I’m going to let Blake wants to answer that. And then we have Tim Ondrak, our leader of the Power business, who can obviously talk more intelligently about it as well. But it’s a really good question, Jim. Like there’s obviously the equipment, and that’s what I think most people in the market have a much clear line of sight of it costs X and therefore, you rent for Y and you have return. But when you get into these behind-the-meter solutions, right, depending on to the function, like the function of the facility, there’s different requirements for the balance of plant, different [ future model ] equipment that you need. And so that can change that dollar per megawatt provided, both on the front end and then therefore, what you have to charge.

Our strategy has been like let’s get in really early with some of these customers that we know they’re making big investments in facilities and they’re facing — they’ve been — the grid has indicated them like, hey, you’re not getting on for what you require really get to understand what they’re trying to accomplish within their activities and do a lot of front-end engineering to really meet their needs. And that can have a pretty broad range in terms of what — like, one, what our facility costs and two, what we have to charge them because we’re always going to be targeting a strong unlevered return on our capital deployed. And obviously, when it comes to return on equity, with the leverage you use on these, it gets pretty attractive. So thinking about like these first ones, there’s going to be a pretty broad range, and that’s why we’re excited to share the economics on things.

And we’ll be very transparent about that as we consummate deals.

John Turner: And I also think that it is the reason why it’s taken a little longer to sign. Another comment on why it’s taken us so long to sign these agreements is that these just aren’t generator rental agreements. These are actually — you have to go in and do planning, engineering. You have to do — you have to line up all the equipment. You have to do — there’s a lot of different things that you have to do on that front. So I think that’s why it’s taking longer than [indiscernible].

Blake McCarthy: It also makes those facilities much stickier because it’s fit for purpose.

Tim Ondrak: Yes. And I think just to kind of close out, I think our strategy is bridge to permanent. And when we look at the thesis that really drives that, we view power as a structural need. And so depending on the utility region and where folks are building out their facilities, those delays can be 2028 all the way up to, I think we’ve heard 2034 from some people. And so when a customer looks at what their power need is, as they start their facilities, it can be substantially less than their growth intentions. And so the model that we have to execute on that is to provide mobile power generation into a permanent facility that meets that long-term need and gets the customer to a place where they don’t need to worry about a utility time line and they can worry about operating their business.

Operator: The next question is coming from Derek Podhaizer of Piper Sandler.

Derek Podhaizer: I want to keep going on the economics question. So obviously, there are some numbers out there. We talk about plus or minus $300,000 per megawatt per year of EBITDA, kind of compare that to your current financing costs. Maybe just help us understand when you talk about the recips building the facility, the balance of plant included in there, how should we think about the economics and the earnings of these potential projects that you’re working on? Just maybe a little bit of help around that as far as some of the numbers that we’re hearing out in the market.

John Turner: Yes, I’ll start off and Blake can chime — he can follow up. I mean economics, obviously, like we said earlier, depend on a number of factors. If you talk about balance of plant facility development, those are common and our turnkey behind-the-meter solutions. And then obviously, balance that with the initial contract term will be focused on longer-term contract structure for stability. Our goal is attractive internal rates of return, well above our cost of capital on the initial term with upside from extensions and expansions. Do you want to add to that?

Blake McCarthy: Yes. Derek, kudos to you, I’m really glad you asked this question. So I think it’s a great question because I know people want to have some type of metric to plug in their estimates. John’s comment on IRR is probably the best way to back to order to that. So for these projects, we’re targeting unlevered IRR in the high teens, which we find very attractive considering the contracted nature of these cash flows. So when you layer on any type of leverage on top of those cash flows, the returns on equity, as I mentioned, get very attractive. Thus, like from a long-term perspective, I think that people talk about that like $300 per megawatt. That’s probably a good proxy for just equipment alone, but it’s a little too simple when it comes to like you’re actually doing these bespoke power facilities.

So I think that using that IRR and we disclosed kind of the — obviously, the magnitude of our facility has been disclosed. I think that’s a good way to kind of back door into getting there. You should be able to use that and the cost of equipment, you get a decent proxy for cash flows that we expect off these projects.

Derek Podhaizer: Got it. Okay. Great. That’s super helpful. And then just my follow-up as far as a question around lead times for your additional equipment. You talked about going 400 to 500 megawatts of deployed capacity. Is this going to be a continuation of the 240 megawatts, those larger 4-megawatt recips that you recently ordered? And if so, how should we think about when you’d be able to get those deliveries and the lead times around that? And then really beyond the potential 500 megawatts, maybe line of sight on the future orders beyond the 500.

John Turner: Yes. I mean thanks, Derek. I’ll take that question if anybody — Tim, if you want to chime in on this. I mean our relationships with the key OEMs and our differentiated track record of execution on large-scale infrastructure projects continue — those continue to be major advantages, which enabled us to initially secure the 240 megawatts of the 4-megawatt reciprocating units that are going to be delivered for later in 2026. And also gave us — also enable us to maintain a solid line of sight to additional equipment for high-quality opportunities and more than 2 gigawatt pipeline that we’re talking about. These relationships are built on trust, scale and early positioning have given us access to redirected capacity from delayed projects elsewhere in the industry.

So lead times for additional 4-megawatt recips are now extending into late 2027, which reflects the strong industry-wide demand for behind-the-meter generation equipment. That said, our recent $375 million lease facility provides flexible nondilutive support tailored to our needs to allow milestone payments during the packaging conversion into term finance upon delivery. That is — this has been instrumental in funding our initial 240-megawatt commitment and positions us well for near-term deployments as we move towards our target of 500 megawatts by 2027. So with the majority of that under long-term contract. As far as beyond 2027, particularly as we pursue larger, denser behind-the-meter opportunities across diversified end markets, we anticipate needing additional financing to support further equipment orders.

We’ve actively evaluated options that align our disciplined capital approach, leveraging our proven track record with financing strong cash flow generation from bridge to permanent transitions. I think that as far as additional equipment packages, I mean, yes, right now, the package that we’ve acquired is these 4-megawatt recips. I mean, there could be other potential opportunities out there, and I’ll let Tim comment more on that.

Tim Ondrak: Yes. So Derek, I think there’s equipment available I think if you look at global capacity, a lot of it has been backlogged. I think there’s been a lot of announcements publicly to kind of back into what may be left. So we really see 2 pools of equipment that come available. The first pool is where you have to be in the market, you have to be talking to people and orders cancel or portions of orders cancel or get delayed. And so there’s equipment that comes to market. And I think there’s a second where OEMs are doing the same thing that we’re doing where they’re outbuilding relationships with the groups that are putting these in place. And I think as John alluded to, we’re in a strong position to take advantage of those relationships.

You look at the folks that are on this team and the relationships that they bring and then you look at the reputation of Atlas in being able to manage and develop these substantial projects. And I think that gives confidence to OEMs that when they place assets with Atlas, it’s going to be a good long-term relationship, and it’s going to give all of us a good name. So I think that’s what we’re leaning into, and we’ve got line of sight into the equipment that we would use to take us to that 500 megawatts.

Operator: Our next question is coming from Stephen Gengaro of Stifel.

Stephen Gengaro: I guess staying on the power theme. One of the things we’ve sort of learned over the last couple of years was there’s a skill set required to sort of deploy these assets at the site and operate them effectively and efficiently. Can you talk about sort of your internal expertise to execute these behind-the-meter projects?

Blake McCarthy: Yes. I’ll lead off on that and then again, defer to Tim, who’s again, much more well spoken on this subject. But when you think about the history of Atlas, right, I mean we’ve got a lot of experience in building big complicated facilities, right? So we constructed the Kermit and the Monahans facilities from where there’s just a bunch of dirt out there in West Texas to some of the more sophisticated sand manufacturing facilities in the industry. And then you got to remember that we’re the guys that thought it was a good idea to build a 42-mile conveyor belt in the middle of the desert, which I think a lot of people roll their eyes at that concept and then lo and behold, here we are a year later, and it’s — that’s moving.

So I think that when we have these initial conversations, people are like, wow, these guys are good at building big complicated infrastructure projects from the ground up. And then you combine that with the electrical expertise that we brought in-house with the Moser acquisition. And then we haven’t been sitting on our hands since we did that deal. We’ve been bringing in quite a bit of talent, really, really strong people in terms of adding to that roster. And when you combine those 2 things, it becomes really powerful. And then you — as people learn about Atlas, and this thing has been — this is a different customer set than we’ve ever dealt with, right? This isn’t just the 25 E&Ps that we all know and love. It is — this is across the broader economy.

And so there’s a lot of education about who is Atlas that we have to do with them. And once they start to see like who we are and what we’ve done, they get a lot of comfort around that. And then we bring in some of our electrical experts and they start to wow them with their knowledge. Those those commercial discussions progressed pretty quickly. I’ll turn it over to Tim for actual specifics, though.

Tim Ondrak: Yes. So I think Blake touched on a couple of things there. I think, first and foremost, when we acquired Moser, we got a team with a 50-year operating history. And so that was a great place to start from, from a talent perspective. We added to that team with some outside talent that have helped us substantially in the C&I and the larger megawatt deployments. And then from a long-term perspective, we’ve built an operating team with 20-plus years of experience in operating large engine systems. And so we really think combining all of those things, we’re able to deliver the same level of execution that we’ve delivered in the sand and logistics space and brought that over to the power space.

Stephen Gengaro: Okay. No, that’s helpful. That’s good color. The other question I had is, and you mentioned, I think, in response to a prior question, the sort of the delays in grid interconnection. And you also, I think, made a comment about you sort of think about this as a bridge to permanent power. But it feels to us like that bridge to permanent power is pretty long. And I was just curious what you’re hearing on the utility interconnection side and kind of the queues for larger loads to be delivered and how that kind of impacts your planning and thought process?

Tim Ondrak: Yes. So I think that’s a big question. And I think that’s a big question because when you look at the utility network in the United States, it is incredibly complicated, right? The rules change sometimes as you cross the street. And so when we’re talking to folks about their projects, every one of them has a different story with similar themes. And the similar theme is that utilities aren’t going to get there. And so they need to look at what they call a bridge solution, but I think when you really understand the challenges that the utilities face and you see projects from the utilities push in different districts, you understand that that’s going to affect really the entire industry. And so what we’re hearing from utilities, and I think I mentioned this earlier, it’s anywhere from 2028 to 2034 for a load to interconnect, and that’s kind of across the U.S. And there are some places where you can pull data points that say it’s longer, it’s shorter.

But if you take that perspective, what we’re really talking about is infrastructure. And so you can bridge that, and I think we’ve got a good solution to bridge that. We’ve got 200 megawatts plus of bridge equipment in what we acquired from Moser. But our — again, our thesis is this is a long-term infrastructure play. And so that bridge system has some disadvantages. And the way you solve some of those disadvantages, whether they’re fuel efficiency, footprint, whatever is you install a long-term system that is designed to sit in place and operate. We talk about 5- to 10-year contracts, 15-year contracts, but really, these are 30-year facilities that they need to be. And so we think that structural shift in this market is going to benefit those that take ownership of that and install their own systems today.

And we think the broader grid really benefits from private capital installing broad infrastructure really across the entire United States.

Blake McCarthy: Yes. I mean, Stephen, it’s such a fluid space, too. Like I feel like every morning, there’s 4 or 5 headlines around that interconnect to getting longer and pushing to the right. And I think we’re all pretty big believers in that there’s going to be more and more pressure on the utilities to probably stiff arm some of these interconnects, too, just because we think that affordability is going to become a bigger, bigger buzzword in the political landscape. And it’s just — it’s probably in everybody’s best interest for the private sector to solve this problem as opposed to leaning on the public utilities to get it done.

John Turner: Yes. Even if they can get power from the grid, they can’t get all of their power from the grid. So I mean, like Tim said, we’re not only talking to end users, we’re talking to the providers. And these are the — this is what we’re getting from the providers is that we may be able to provide some of the power, but we’re not going to be able to provide all the power. And they’re also being told that in order for us to provide you power, you need to show us that you can provide yourself — supply yourself with a certain amount of power to get that additional power from the grid. So obviously, a lot going on, a lot changing here, but that’s kind of where it is now.

Tim Ondrak: Yes. And I think the one last point I’ll make on that is we’re out and we’re talking to people every day and they’re looking at big projects. And the 2 things that are most consistent are: one, the utility has moved the goal line on when they’re actually going to show up; and two, that they’re not going to meet the full request for power.

Operator: The next question is coming from Doug Becker of Capital One.

Doug Becker: I think the questions are really appropriately focused on power up to this point, but I did want to touch base on the sand and logistics business. First half volumes look very good. I appreciate the lack of visibility around the second half of the year, but any type of range you could provide for production growth for the full year to kind of give us some goalposts to think about?

Blake McCarthy: Yes. I mean it’s a good question. And sorry for being opaque, but right now — and I appreciate part of our customers, too, is that the outlook is a little opaque. I think that if you rewind 3 months ago, it seemed like every macro note you’re reading was point of oil being $45 to $50 at this point in the year. And here we are sitting at $66 WTI. Granted, there’s a lot of geopolitical risk premium built into that, but I don’t think any of us think we live in a world where there’s not going to be geopolitical risk. So our commercial team did a great job of going out there, and we told them, hey, go get the volumes. And they went out there and they did that, and it sets us up for a very strong first half. That being said, there’s — a lot of our customers were — they’re like, hey, like we’ve got our schedule for first 6 months of the year.

And we’d like to leave a little bit of optionality on what our plans — our schedule looks like in the second half of the year. So I think a lot of that’s dependent on the commodity tape. Right now, from where we sit, our expectations are for our overall volumes to be up year-over-year. That would imply — and that gives us — I appreciate that, that’s a pretty big window in terms of second half volumes because we do expect to have pretty significant volumes in the first half of the year. That being said, like the pricing environment remains pretty challenging. So that’s obviously a headwind. But we’re — so that has us focused on things we can control, which is driving down the variable cost of our production at the plants. We’re pretty excited about the dredge commissionings that we’ve got coming up later this quarter and into Q2.

That’s going to drive some significant improvements in our Kermit facility. I think that really our objective on the sand and logistics side is to just really cement ourselves as the leading sand logistics provider in the Permian and position ourselves so that when the cycle does turn, hey, we’re that sticky supplier of quality that, hey, nobody wants us not to be delivering sand onto their well site because we make it where their operations doesn’t have to think about it.

Doug Becker: That’s fair. On the logistics side, highlighted the trucking challenges, but pointed out some upward momentum in trucking rates. Just any color on the margin outlook in logistics for this year after a pretty slow start on the margin front with the Dune Express.

Blake McCarthy: Yes, that’s a good question. And I tried to give a little transparency on that because I think it’s a question we get a lot. We’re positioned to move to improve off a low base we ended 2025 and started 2026 with. So during both late Q4 and early Q1, our logistics business was burdened by pretty heavy load bonuses that we offered to third-party carriers to ensure that we have the drivers available to meet customer needs during the holiday season and to ensure delivery when, quite frankly, the weather’s pretty miserable, which certainly was in January. Additionally, as we mentioned in the prepared remarks, like I said, our sales team was — they were really feeling their oats during the contracting season. So they’ve done a great job securing pretty attractive work in what is a really tough market.

And that includes a good amount of work that’s going to drive incremental Dune Express volumes, which is the biggest driver of creating more margin differential in a weak pricing environment. So from a numbers perspective, Doug, I think logistics margins in Q1 probably going to look pretty similar to Q4 with December of last year and January of this year representing low points. And then Q2 is currently like loose projections right now, but I’ve taken a nice step up into the double digits, maybe not quite mid-teens, but a nice step up and a huge relative gap to where the rest of the market is.

Operator: The next question is coming from John Daniel of Daniel Energy Partners.

John Daniel: First question is, can you speak to the actual number or the volume of power increase coming from the E&P operators for microgrids? And then have you tried or will you try to tie sand volumes to contracts for that power?

Tim Ondrak: John, yes, so the volume of increase on microgrids coming from E&P, I think what we’re seeing is a little bit basin dependent. But in probably our 2 of our 3 most active basins, I would say about half of the new requests coming in for well site generators are in some type of microgrid system. And that’s typically tying anywhere — the production from anywhere from 2 to maybe 4 pads together. But we expect that as the year progresses, we will allocate more and more units to those types of systems. As far as tying the sand volumes to the power, that’s obviously a good idea. We like to be — we want to be a broad provider of solutions for our customers as of now. A lot of the teams that deal with those are separate.

You got completion teams that are working versus the production teams that they’re mostly different in a lot of these organizations. But from a sales standpoint, we’re always working to be a better solutions provider for our customers. So that — I’m not going to count that out of the question.

Operator: Our next question is coming from Eddie Kim of Barclays.

Edward Kim: Just wanted to circle back to the volumes theme. You mentioned that you’re adding — sorry, you’re in discussions on adding new customers this year and you’re taking greater share of the wallet with your existing customers and it seems like you’ve been successful with that. Just to be clear, are those wins fully reflected in your first quarter volumes guidance? Or do those volumes really start to kick in later in the year?

John Turner: I would say those wins are not necessarily reflective in our first quarter volumes. I mean first quarter volume is going to be depressed some because of the weather. But I would expect to see some of those impacts kicking in as we move. You’re going to see some of it in the first quarter and then it’s going to kick in second and third.

Blake McCarthy: Yes. I mean like there’s always a ramp in customer activity. January always starts a bit slow, and we have a steady ramp through the course of the quarter. And then that winter storm in January, obviously, it knocked out about 4.5 days of operations out there for everybody. And so not fully reflected in those volumes. We — our expectation is for Q2 volumes to be a step-up from Q1.

Edward Kim: Got it. And then just sticking on that theme, I mean, you mentioned strong volumes in the first half, but customers taking sort of a wait-and-see approach in the second half. I guess just based on your conversations, it seems like E&Ps might not really be buying this $65 WTI oil price right now. And are they, do you think, still operating as if we’re in kind of the mid-50s environment? And I’m just curious what oil price do you think we’d have to get down to for them to consider a volumes reduction in the second half of the year?

Blake McCarthy: Yes. I think that their budgets for this year are based around like $50 to $55 oil. And I think today’s activity in West Texas is reflective of that commodity strip. And they’re not going to deviate from their — they’ve just set those CapEx budgets, and they’re not going to deviate from that just on gyrations of the commodity price. But the longer the commodity price stays up and people get more comfortable with it, but I’m sure they’re not complaining about the incremental cash flows they’ve got — they’re ripping off right now.

John Turner: I mean, the whilst, the investment cycle — I mean, the decision time line is pretty short. So they can wait longer with these shale wells to go out and make a decision. So I think like Blake said, they’re comfortable where they are now. And if that continues, you’ll probably see steady activity through the end of the year, but it just depends on where prices go.

Operator: The next question is coming from Michael Scialla of Stephens.

Michael Scialla: You mentioned the last mile storage system. I just wanted to ask about that, allows continuous pumping of wet sand. You said you’re testing the dry sand solution. What needs to happen there for that to be successful? And what could the opportunity be for that system if it works?

John Turner: Yes. So earlier this year or late last year, we launched a system that was designed for really well site increasing the amount of sand that’s delivered to the well site, timeliness of that, that’s going to increase the efficiencies to enable operators to pump downhole more sand. We’ve been seeing — and we kicked this off on the wet sand side. We have all of those systems deployed right now. And we do have a number of our customers that are using them that want more. As far as the dry sand goes, there’s still going to be some work that we’re going to have to do on that front. And as far as timing goes, it’s way to be seen, but there’s some testing that we’re working on, and we’ll be able to comment more about that here later.

But we do — what we are seeing the results of that are promising. And I think some of the things — some of the themes you’re going to see going forward is continuous pumping. A lot of our customers are asking it and requiring it because and you’re starting to see some significant results from our delivery of sand to the well site that enables things to things like the Dune Express and our wet sand offerings. And then this is just another step in that direction of helping our customers with their needs and providing them with solutions that work that enable them to accomplish their goals.

Blake McCarthy: Yes. And then the continuous pumping thing is such an important trend in our space. Those are — the completion crews we’re providing sand to that are on continuous pumping operations, the amount of sand they pump monthly is multiples of what you’d see from a traditional zipper crew. But the big constraint, right, is it becomes well site footprint, things like boxes and silos, they are constraints, right? And so the pile system, like going to piles, obviously allows you to put more sand in one spot. But what we think our system does is it enables do piles, but to do it very efficiently and with clean sand and you combine that with the PropFlow technology. It is a key enabler of very, very efficient continuous pumping operations.

And it’s something that just continues to push that tailwind of the sand intensity of each individual completion crew, which we think long term is a — when people stop planning budgets around $50 oil and maybe get a little bit more comfortable around something like $65 plus, see a little bit more incremental activity, we think the market tightens up pretty darn quick.

Michael Scialla: Appreciate that detail. Also wanted to ask about your — you mentioned your hybrid power system. I guess, what differentiates that? And what’s the opportunity for those assets look like?

Tim Ondrak: Yes. So the hybrid power system is it’s essentially combines battery technology that we’ve developed in-house on the patents on, and that was funded through a DoD grant that the legacy Moser business obtained in 2018. And what that system essentially does is hybridizes with our existing generators. And it controls the operation of those generators so that they run at essentially a peak load and the battery then distributes power into that system, shuts the generator off. And so what it does is it lowers the run time on those generators, which extends our maintenance cycles from essentially once a month service to once every 45 days as much as once every 60 days. It lowers the fuel cost for our operators and it decreases the risk of a shutdown event on the customer’s location, which those are not good for downhole pumps, which is primarily what we do in that business.

And so we’re pretty excited about the potential to deploy that at scale in the legacy Moser business. We think it’s differentiated. We’ve proven it on multiple well sites. But I think when you apply that to the broader industry outside of oil and gas, it’s got uses really across every industry where folks want more clean, reliable power and that battery system provides clean, reliable power that can integrate with whatever systems they’re using, whether they’re prime power systems or backup systems.

Operator: Our final question today is coming from Jeff LeBlanc of TPH.

Jeffrey LeBlanc: I wanted to see if you could provide some color on the expected cost savings over the second half of the year once the Twinkle dredges come online…

John Turner: He wants to get at the cost savings that we’re going to expect in the second half of the year once the dredges come on? Yes. And I’ll let Blake cover that.

Blake McCarthy: We haven’t had a steady dredge feed at our primary Kermit facility for going on over a year now. And that facility is really designed to have a clean, steady dredge feed. And so what that’s created is just different bottlenecks in the process that has elevated the OpEx per ton coming out of that facility versus — I mean, when that facility is cooked, it is our lowest — it’s the lowest cost facility in the entire Permian Basin. So as those 2 dredges come on and I just highlight that these are — these Twinkle dredges we’ve had. We’ve had a Twinkle dredge in the fleet got one in the fleet now, and that is the most consistent producer we’ve got. So we’re very confident and we think they’re the F-150 dredges. Getting those online will significantly enhance the quality of our dredge feed, which has just really positive knock-on effects to the entire process.

It improves wet shed operations. It reduces stress on the dryers. It just makes the whole facility run more efficiently. If you think about that, our overall variable costs probably have been elevated by about $1 across the complex because of those dredge feed issues. And so that’s over the course of the first half of the year, that will flow on. And there — so it’s — again, it’s a pretty big circular reference, though, in terms of the overall OpEx per ton just because so much of that is based on volume throughput, and that’s dependent on customer activity in the second half. But if you were to just extrapolate first half activity in the second half, you’d see a pretty significant improvement in OpEx per ton as we work through the year.

Operator: At this time, I’d like to turn the floor back over to Mr. Turner for closing comments.

John Turner: Thank you, operator, and thank you all for joining us today and for all the great questions. We truly appreciate the time you’ve taken with us to our exceptional team. Thank you for all the hard work. To our customers, thank you for your partnership and trust and our investors. Thank you for your committed and continued support, belief in Atlas. We look forward and are excited about reporting our results going for 2026 and our first quarter results here in 2 or 3 months. Thanks, everyone, for joining, and that ends the call. Thank you.

Operator: Ladies and gentlemen, thank you for your participation. This concludes today’s event. You may disconnect your lines or log off the webcast at this time, and enjoy the rest of your day.