- Par Pacific Announces Pricing of Private Placement of $500 Million of 7.375% Senior Notes due 2034
May 12, 2026
HOUSTON, May 11, 2026 (GLOBE NEWSWIRE) -- Par Pacific Holdings, Inc. (NYSE and NYSE Texas: PARR) (“Par Pacific” or the “Company”) announced today that Par Petroleum, LLC, a wholly owned subsidiary of Par Pacific (“Par Petroleum”), priced a private placement (the “Offering”) pursuant to Rule 144A and Regulation S under the Securities Act of 1933, as amended (the “Securities Act”), of $500 million in aggregate principal amount of 7.375% senior unsecured notes due 2034 (the “Notes”). The Notes mature on June 1, 2034, and will be issued at par. The Notes will be fully and unconditionally guaranteed on a senior unsecured basis by Par Pacific and each of Par Petroleum’s subsidiaries that guarantees the Company’s senior secured asset-based revolving credit facility (the “ABL Credit Facility”) at the closing of the Offering. The Offering is expected to close on May 14, 2026, subject to customary closing conditions.
The Company intends to use the net proceeds from the Offering, together with cash on hand or borrowings under the ABL Credit Facility, to repay all of the aggregate principal balance under and terminate Par Petroleum’s term loan due 2030.
The offer and sale of the Notes and the related guarantees have not been registered under the Securities Act, or any state securities laws, and unless so registered, these securities may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The Company plans to offer and sell these securities only to persons reasonably believed to be qualified institutional buyers pursuant to Rule 144A under the Securities Act and to non-U.S. persons outside the United States pursuant to Regulation S under the Securities Act.
This news release shall not constitute an offer to sell, or the solicitation of an offer to buy, any of these securities or any other securities, nor shall there be any sale of these securities or any other securities in any state or jurisdiction in which such offer, solicitation or sale would be unlawful.
About Par Pacific
Par Pacific Holdings, Inc. (NYSE and NYSE Texas: PARR), headquartered in Houston, Texas, is a growing energy company providing both renewable and conventional fuels to the western United States. Par Pacific owns and operates 219,000 bpd of combined refining capacity across four locations in Hawaii, the Pacific Northwest and the Rockies, and an extensive energy infrastructure network, including 13 million barrels of storage, and marine, rail, rack, and pipeline assets. In addition, Par Pacific operates the Hele retail brand in Hawaii and the “nomnom” convenience store chain in the Pacific Northwest. Par Pacific also owns 46% of Laramie Energy, LLC, a natural gas production company with operations and assets concentrated in Western Colorado.
Forward-Looking Statements
This news release includes certain “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to qualify for the “safe harbor” from liability established by the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are forward-looking statements. Forward-looking statements include, without limitation, statements about the expected timing of the closing of the Offering, the intended use of proceeds therefrom and other aspects of the Offering and the Notes. Forward-looking statements are subject to certain risks, trends and uncertainties, such as the risks and uncertainties detailed in the Company’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other documents that the Company files with the Securities and Exchange Commission. The Company cannot provide assurances that the assumptions upon which these forward-looking statements are based will prove to have been correct. Should any of these risks materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those expressed or implied in any forward-looking statements, and investors are cautioned not to place undue reliance on these forward-looking statements, which are current only as of the date of this news release. Except as required by applicable law, the Company does not intend to update or revise any forward-looking statements made herein or any other forward-looking statements as a result of new information, future events or otherwise.
Investor Contact:
Ashimi Patel Vitter
VP, Investor Relations & Sustainability
(832) 916-3355
apatel@parpacific.com
- Kodiak Gas (KGS) Q1 2026 Earnings Transcript
May 11, 2026
Image source: The Motley Fool.
DATE
Monday, May 11, 2026 at 11 a.m. ET
CALL PARTICIPANTS
President and Chief Executive Officer — Mickey McKee Executive Vice President and Chief Financial Officer — John Griggs Investor Relations — Graham Sones
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Full Conference Call Transcript
Graham Sones: Good morning, and thanks for joining us for the Kodiak Gas Services, Inc. conference call and webcast to review our first quarter 2026 results. Joining me from the company today are Mickey McKee, President and Chief Executive Officer, and John Griggs, Executive Vice President and Chief Financial Officer. After my remarks, Mickey and John will cover recent market developments, share an update on our power strategy, and walk through our results and updated 2026 outlook, including our new power segment. Then we will open it up for Q&A. A replay of today's call will be available by webcast and phone through May 25, 2026. Replay details are on the Investors tab of our website at codietgas.com.
As a reminder, the information discussed today speaks only as of 05/11/2026 and may no longer be accurate by the time you listen to a replay or read a transcript. The comments made by management during this call may contain forward-looking statements within the meaning of U.S. Federal Securities Laws. These statements reflect management's current views, beliefs and assumptions based on information currently available. Although we believe the expectations referenced in these forward-looking statements are reasonable, various risks, uncertainties and contingencies could cause the company's actual results, performance, or achievements to differ materially from those expressed in the statements made by management, and management can give no assurance that such statements or expectations will prove to be correct.
The comments will also include certain non-GAAP financial measures. Details and reconciliations to the most comparable GAAP measures are included in our earnings release, which can be found on our website. Now, I would like to turn the call over to Kodiak Gas Services, Inc.'s President and CEO, Mickey McKee. Mickey?
Mickey McKee: Thanks, Graham. Thanks to everyone for joining us today. I want to start like we do in all meetings at Kodiak with safety. As we head into the summer driving season, it is a good reminder that driving is one of the riskiest things many of us do every day. That is why we have all Kodiak employees complete a safe driving program, and we rolled out telematics last year to help reduce distractions when behind the wheel. Thank you to our safety and training teams for equipping our people with these valuable tools, and to everyone at Kodiak for living our safety-first mindset every day.
Story Continues
Recent geopolitical events have served as a stark reminder that energy security and reliable energy infrastructure are critical to our daily lives. The energy landscape keeps evolving, with rising demand for natural gas tied to LNG exports and power generation, including data centers as the AI race accelerates. This step change in demand is straining supply chains, pushing equipment lead times to records, and increasing the need for highly trained technicians to keep large horsepower equipment running. Kodiak Gas Services, Inc. is well positioned to meet this challenge. Our supply chain team has been proactive in sourcing new equipment for both compression and power, and our highly skilled workforce is ready to keep delivering the service our customers expect.
The natural gas compression market is in uncharted territory. Lead times for new large horsepower equipment keep extending and now sit at over 180 weeks for 3,600 inline gas compression engines—over three years. Through our strong vendor relationships, we have secured new large horsepower compression packages for 2027 and 2028, and we are working to secure additional units for 2029 delivery. We remain confident in our ability to achieve our targeted annual horsepower growth of 150,000 horsepower per year, resulting in a compression fleet of at least 5.2 million horsepower by the end of the decade.
While supply is limited, compression demand is building across both our E&P and midstream customers as they now have increased visibility into the next wave of natural gas volumes. Permian operators are starting to pick up activity with higher oil prices and record U.S. oil export volumes, and with more than 5 Bcf per day of Permian gas takeaway capacity expected online by year end, several customers have asked whether they can accelerate their 2027 equipment orders. This has manifested itself in our pricing, as we have demonstrated continued pricing power we expect to continue into 2027 and beyond, given the tightness in the market.
One thing to keep in mind is that Kodiak Gas Services, Inc. has consistently high graded our fleet over the last couple of years, strategically divesting some of our noncore small horsepower compression that commands a higher dollar per horsepower revenue rate but at a lower margin. We have increased our average horsepower per unit in our fleet from 943 horsepower per unit at the end of Q1 last year to 977 horsepower per unit currently, while also driving up the average dollar per horsepower revenue rate, effectively overcoming industry dynamics for revenues per horsepower while our peers' horsepower per unit has collectively gone down over that time period.
Another dynamic we are seeing is customers signing longer-term compression contracts to lock in equipment availability. During the quarter, we entered into a 10-year compression services contract extension with one of our top customers, and we are in the process of finalizing another 10-year extension with another top customer, further demonstrating the infrastructure nature of the large horsepower compression business. Also in the first quarter, we purchased a package of large horsepower compression units from a Permian producer and signed a seven-year contract to provide compression services.
This was important for a few reasons: it is an accretive way to grow market share and generate immediate cash flow in this long lead time environment; it also reinforces what we hear from customers—Kodiak Gas Services, Inc. can operate units efficiently and cost effectively. Next, I want to talk about our Distributed Power business, now going to market as Kodiak Power Solutions. We closed the DPS acquisition on April 1, and we have been moving quickly on integration. We are already operating on the same ERP platform, and we have realigned our commercial and operations teams to support the business.
DPS brought a strong commercial team with deep distributed power experience, including one of the first islanded primary power data center contracts, which is now in its third year of operation and has capably delivered on its 99.9% reliability guarantee to its customer. I will touch on a few reasons we are excited about the long-term growth in distributed power. The power market is evolving quickly. Texas leads the nation in data centers under development with over 150 currently in development, as hyperscalers prioritize low-cost energy, available land, and a constructive regulatory environment in the site selection process. One recent estimate says there are over 30 gigawatts of planned data centers in Texas over the next two years.
Speed to power also matters. The AI world is moving fast; delays can put projects at a disadvantage. Behind-the-meter solutions are not just short-term solutions; they are increasingly cost competitive with grid power, often with similar or better reliability. We are currently in discussions with a number of data center customers about long-term contracts at high-quality returns to provide primary power. The opportunity set is significant, and we expect it will keep growing as hyperscalers expand their CapEx plans. Recent estimates indicate the hyperscalers' AI-related CapEx spending between now and 2030 may exceed $5 trillion.
Given the significant level of digital infrastructure and microgrid demand that we are currently experiencing, and our focus on moving quickly to capture the opportunity, we have been very active in sourcing additional power generation capacity. As noted in this morning's press release, we have sourced additional power generation capacity to add to what we acquired with DPS. We have currently placed orders for more than 260 megawatts, with about 61 megawatts to be received in 2026 and the remainder between 2027 and 2029, and we are in advanced discussions with multiple counterparties for an additional 1.3 gigawatts to be delivered on a relatively ratable delivery schedule through the end of the decade.
The equipment we are buying is a mix of recip engines and industrial gas turbines that are purpose-built for data center and microgrid applications. This is consistent with our power growth strategy targeting growth of 300 to 500 megawatts per year through the end of the decade, equating to a distributed power fleet of around 2 gigawatts by year-end 2030. Based on the discussions we are having today, we expect our investment in power equipment to generate unlevered returns greater than 15%, EBITDA build multiples around 5x, competitive with our compression business after factoring the added benefit of increasing the average duration of our contracted cash flow with high-quality customers.
As we invest to grow both our contract compression and distributed power assets, we are committed to maintaining financial flexibility and having a strong balance sheet. Our contract compression business is generating highly resilient free cash flow, which will help fund our power growth. Plus, we have ample liquidity on our ABL and a variety of financing options available to us as we undergo this period of strong infrastructure growth. The investments we make today will help build a stronger, more profitable company in the future. This morning, we released our first quarter 2026 financial results. I will hit a few highlights, and I will let John go into more detail.
We ended the first quarter at 4.4 million revenue-generating horsepower. Average horsepower per revenue-generating unit was 977, the highest among our contract compression peers, and a figure we expect to keep moving higher given our large horsepower focus. Our investments to grow the fleet, along with divestitures of noncore units, drove fleet utilization to 98%, another industry-leading metric. In Q1, we delivered strong year-over-year growth in contract services revenue and adjusted gross margin. Contract services adjusted gross margin was 70.6%, a seventh consecutive quarterly increase and a new high for Kodiak Gas Services, Inc. Margin gains continue to be driven by strong operational execution and returns on our technology investments.
Real-time equipment monitoring is helping us catch issues earlier, reduce failures, increase operational efficiency, and lower parts spend. In our Other Services segment, first quarter results reflected a sequential pickup in station construction activity along with better margins on AMS services. Strong results from each segment drove adjusted EBITDA to $190 million for the quarter, up 7% year over year and a new company record. Looking ahead to the rest of 2026, we see continued strong momentum in compression. We are fully contracted for our 2026 new unit compression deliveries, and are making strong progress on our 2027 deliveries with over 40% already contracted.
Our updated guidance reflects both the incremental contribution we expect from Power and the investment we are making to scale that business and drive growth for years to come. Now, I will pass the call to John Griggs to further discuss our financial results and our revised outlook for 2026. John?
John Griggs: Thanks, Mickey. You summed it up well. Kodiak Gas Services, Inc. has a lot of positive momentum. Our compression business continues to set new records in both revenues and margins, and the growth and return potential for our new power business is extremely compelling. Now let us turn to the quarter's results. We reported total revenue of $346 million, up 5% year over year. The growth was primarily driven by new horsepower, price increases, and strong operational execution. In contract services, revenues increased 6% year over year and 2% sequentially. Revenue-generating horsepower increased by approximately 35,000 sequentially. We realized a 3.7% year-over-year price increase to $23.31 per ending revenue-generating horsepower.
This uptick was impressive considering that approximately 20,000 of this quarter's horsepower increase came at the end of the quarter via the purchase-leaseback transaction Mickey mentioned and therefore had no meaningful impact on revenues. A real bright spot was our contract services adjusted gross margin of 70.6%, up 138 basis points sequentially and 286 basis points year over year. This high watermark is further proof to us that the significant investments we have been making in our training and operational technology over the last couple of years are generating real returns.
During the quarter, we realized a reduction in compression parts expense as our investment in telemetry technology and data analysis has allowed us to monitor equipment more closely, leading to a reduction in failures and spend. We are also gaining efficiencies through the connectivity of our technology platforms, making information more rapidly available to our skilled technicians. All of this leads to more informed, real-time field-level decisions, which then tends to result in improved run time and even better customer service. In Other Services, revenues rose 25% sequentially as we saw increased station construction activity during the quarter.
We realized a sequential margin increase to around 16% as we saw a greater portion of activity this quarter in higher margin revenue streams. Adjusted EBITDA for the quarter was up 7% versus the prior-year quarter, landing at a new company record of $190 million. We reported adjusted net income of $52 million, or $0.59 per diluted share. Let us turn to capital expenditures. Maintenance CapEx was approximately $18 million in Q1, in line with our expectations. Other CapEx was $7.5 million, also in line. Growth CapEx of $86 million included $24 million for the compression purchase-leaseback transaction and $18 million related to new power generation equipment. We will break out the power growth CapEx in future quarters.
The power gen equipment orders we are making average about $1.1 million to $1.2 million per megawatt. We would expect to spend an additional roughly 30% for balance of plant equipment; that BOP figure could vary depending upon the setup required by customers. After backing out the purchase-leaseback and power-related figures, compression growth CapEx was around $44 million, which included the delivery of 18,000 new unit horsepower during the quarter as well as a variety of other items, including fleet revamps and deposits on long lead time engines. Discretionary cash flow was $126.5 million, up 9% year over year, driven by the higher adjusted EBITDA and lower cash taxes.
Moving to the balance sheet, net debt was $2.7 billion at quarter end. In February, we issued $1 billion of senior notes due in 2031 at an attractive rate of 5.75%. We used the proceeds to redeem our 2029 senior notes and pay down our ABL. Our credit agreement leverage ratio was 3.6x as of March 31. Finally, our Board declared a dividend of $0.49 per share that will be paid later this month. Based on our first quarter discretionary cash flow, our dividend remains well covered at 2.9x. Let us turn to our updated 2026 guidance, which we split into the three segments we intend to report going forward.
Contract Services will become Compression Infrastructure and continue to include the same items it did previously. We are creating a new segment called Power Infrastructure, which will include the vast majority of our new power business. A small portion of DPS' historical and future revenues, mainly things like fleet mobilization and logistics, will be reported in our Other Services segment. We will guide and report growth CapEx separately for compression and power to increase visibility. As a reminder, our 2026 guidance reflects just three quarters of contribution from the DPS acquisition. In terms of changes, we increased the low-end Compression Infrastructure revenue guidance to reflect the progress we have made recontracting units and the increased visibility on new unit growth.
We moved up our adjusted gross margin estimate to 68.5% to 70%, up from our original guidance, taking into account the recent rise in oil prices and its impact on our lube oil and fuel expenses in the second half of the year. For Power Infrastructure, we are guiding to full-year revenues of $95 million to $125 million and an adjusted gross margin range of 60% to 70%. We are keeping those ranges wide given the newness of the acquisition, as well as to maintain commercial flexibility to meet the timing needs of longer strategic deployments.
While we expect to take delivery of 61 megawatts of additional power equipment in 2026, we do not expect to realize any material increase in revenue for these units until early 2027. We increased the top end of our Other Services revenue guidance range to account for the addition of the nonrecurring revenues from the Power business I previously mentioned. Putting that all together, our 2026 adjusted EBITDA guidance is now $820 million to $860 million, and our discretionary cash flow guide is $520 million to $570 million. We bumped up each of Maintenance and Other CapEx by $5 million based on the addition of the power fleet.
Compression growth CapEx of $245 million to $275 million is consistent with the March press release announcing the purchase-leaseback transaction, and we remain on pace to add approximately 170,000 horsepower over the course of the year. As for power growth CapEx, as Mickey highlighted, in light of the strong demand signals we are seeing, we are embarking on an investment cycle in power designed to meaningfully increase our earnings power over time. That translates into the addition of roughly 300 megawatts to 500 megawatts per year from 2027 through 2030.
To hit those targets, we expect power growth CapEx this year to range from $400 million to $500 million, with approximately $90 million related to gensets and balance of plant to be delivered in 2026. The remainder is for equipment scheduled for delivery in 2027 plus. I will echo Mickey's comment that we are going to use the strength of our extremely resilient and highly creditworthy compression business to help us fund our initial growth in Power. You should expect us to guard the balance sheet while doing so. With that, I will hand it back to Mickey.
Mickey McKee: Thanks, John. I will wrap up by reiterating that 2026 is off to a great start. Q1 adjusted EBITDA exceeded our expectations. Contract compression market fundamentals remain compelling, with highly visible demand. We are extremely excited about our distributed power business offerings and the opportunities to grow that business. Thanks for your participation today. We will now open the call for questions.
John Griggs: Operator?
Operator: Thank you. To allow for as many questions as possible, we ask that you please limit yourself to one question and one follow-up. Our first question comes from the line of Elias Max Jossen with JPMorgan. Please proceed with your question.
Elias Max Jossen: Hey, good morning, everyone. Just wanted to start on the sort of contracting framework for the backlog. I know that you have provided some incremental color on long-term contracts that you have executed, but how should we think about contracting within the sort of 2 gigawatt backlog target that you have outlined? And should we think about incremental updates as we move forward on that 300 to 500 megawatts of annual capacity that you plan to add?
Mickey McKee: Hey, Elias, thanks for the question. Good morning. I think that we have only owned this business now for five weeks, and we are pretty hyper-focused right now on making sure that we have the supply in place to get the contracts put in place. So we are really focused on making sure that we have the equipment coming to us right now. And then on top of that, we have a tremendous amount of inbounds and conversations that are happening right now both on the data center side and on the microgrid side as well. There will be more updates on those contracts as we go along and as they come in.
We will get those frameworks put together for you, and we will be able to update probably on a quarterly basis going out in the future from here.
Elias Max Jossen: Awesome. And then I think that the competitive edge that you guys have demonstrated from an execution standpoint on equipment procurement is definitely differentiated. So can you talk to us about how you are able to procure in this increasingly challenged supply chain and get this equipment versus others? Any color there would be great. Thanks.
Mickey McKee: Yes, absolutely. It is a challenge right now. This equipment is in short supply; it is difficult to come by. But we are leveraging all the relationships that we have both within the compression industry and with our current suppliers along with some new ones. We have some things that are in the works to develop some long-term frameworks around supply agreements, and we are working hard on those. We will update more on those as we get those finalized as well.
Elias Max Jossen: Alright. Great. Thanks, guys.
Mickey McKee: Thanks, Elias.
Operator: Thank you. Our next question comes from the line of John Mackay with Goldman Sachs. Please proceed with your question.
John Mackay: Hey, team. Thank you for the time. I will pick up on the theme you touched on a few times, but I want to ask it a little more directly. If we are thinking about the CapEx per megawatt here, John, I know you touched on it a little bit, but could you give us a little more color on how you are thinking about that balance of plant spend—maybe frame that up around different customer types—and then any comments on what you are targeting for that customer type mix?
John Griggs: Yes, sure. This is John Griggs. I will answer the first part and flip it back over to Mickey. Thanks for the question. As we said, and I think consistent with what others have said as well, the base power since we are already purchasing some and since we are in deep discussions with OEMs about purchasing more, let us call it $1.1 million to $1.2 million per megawatt. It could vary a little bit between recips and turbines, but that is what we are modeling in. From a balance of plant perspective, we are using just call it $1.5 million per megawatt. It can vary, and the people that are in the business know this quite well.
If you had a data center that wanted all the bells and whistles around their project, then you could very easily be at least 2x what you were in your original equipment purchase, and if you had something that was a less sophisticated application and perhaps you had some of that kit in-house as well, it could be much smaller—1.2x or something. We think $1.5 million is the right number to be using all in.
Mickey McKee: Yes. And on the customer mix you asked about, we have a tremendous amount of conversations happening right now in the data center space that are a mixture of regular digital infrastructure as well as AI compute-type loads. There is going to be a mix of those different kinds of data center customers, and that is the bulk of what we are looking at right now as far as customer mix goes.
John Mackay: Appreciate that color. Second one from me, probably a quick one. Thinking about those different types of customers and different types of balance of plant buildout, are you confident in that return framework you lined up earlier on the call and when you first announced the DPS acquisition?
Mickey McKee: Yes, absolutely. We will model in those costs as we do the engineering upfront on these projects and make sure that the returns meet the expectations and the thresholds that we have already put in place.
John Mackay: All right. That is great. Appreciate the time. Thank you.
Mickey McKee: Thanks, John.
Operator: Thank you. Our next question comes from the line of James Michael Rollyson with Raymond James. Please proceed with your question.
James Michael Rollyson: Hey, good morning, everyone. Mickey, maybe switching to the competitive landscape. If we look at your history in compression, you guys started out to build a better mousetrap from an uptime and customer service perspective, and have been very successful in doing so. As you now venture into the power space, it is obviously a different landscape of people chasing this business. I am curious how potential customer conversations go, and how you win that business over the half dozen other guys that are chasing this as you go forward?
Mickey McKee: Hey, good morning, James. There are a lot of similarities in these businesses. There are nuances and differences in the type of equipment, but we are going to approach it the same way. That starts with the customer service mentality, being a total solutions provider, and backing that with run times and reliability. What we liked about DPS when we bought the business is the fact that they have a data center contract that is totally islanded already, with over two years of operating history at over 99.9% reliability. The service mentality really lines up with what Kodiak Gas Services, Inc. has always brought to the table in compression.
We are confident we can be a provider of a differentiated solution that focuses on our customers and their needs.
James Michael Rollyson: Got it. Appreciate that. And then maybe switching gears to your core business currently. With the long lead times stretching out, you guys are generally on top of it, but how are you planning ahead to ensure engines? Are you looking even outside of CAT to make sure all your customer needs get met, and how are you planning for all that?
Mickey McKee: Yes, absolutely. We are certainly looking out into the future and making sure that we have engines and shop space—which are really the two biggest commodities here—locked up and accessible going forward. We have 2027 and 2028 completely lined up, and we are working on 2029 right now. That coincides with what our customers are looking at with highly visible natural gas demand from LNG and power. We feel like we are staying ahead of it and doing what we have always done: paying close attention to the supply chain and making sure there are no gaps in deliveries.
John Griggs: And James, I would chime in that the 170,000 incremental horsepower that Mickey called out last quarter is totally doable given how we manage the supply chain and the demand signals.
James Michael Rollyson: Great to hear. Not surprising, and thanks for all the color, guys.
Mickey McKee: Thanks, James.
Operator: Thank you. Our next question comes from the line of Douglas Baker Irwin with Citi. Please proceed with your question.
Douglas Baker Irwin: Hey, team, thanks for the time. I wanted to start with the 260 megawatts you have already procured. Can you provide more detail around what that initial mix of equipment might look like—turbines versus recips—and the timeline beyond 2026 for taking delivery? Where do you stand on contracting discussions so far, understanding it is still very early days?
Mickey McKee: Yes. Hey, good morning, Doug. It is still very early days and we are working through a lot of those details. I will tell you that what we have already procured is a mix of recips and turbines. That is going to be our strategy going forward. We think there is a market and a demand for both, and we think having a quality mix of both is the way we want to go forward. The 260 megawatts that we have already procured is probably in the ballpark of 50/50 recip versus turbine.
Going forward, I would think it will be more heavily weighted toward turbines—about 25% recip and about 75% turbine—as we think those turbines, from a real estate standpoint, take up a lot less space, have a lot more power density, and are really good fits for the data center contracts we are chasing and already in conversations on that are typically in the ballpark of 200 to 300 megawatts at a time. That is the plan going forward and how we are going to target growing the business.
Douglas Baker Irwin: That is helpful. Thanks. As a follow-up, can you talk about how the funding requirements for some of this power equipment might compare to traditional compression? How ratable is that $400 million to $500 million of CapEx this year if some of this power capacity requires more upfront payments or deposits for larger turbines, and what are the implications for cash flow if spending is more front-end weighted?
John Griggs: Yes, you bet. Good question. One thing on the 300 to 500 megawatts that we call out from 2027 through 2030—it is not a straight line, but it is pretty tight within that range in terms of the stuff we have already bought or the conversations we are advancing to buy equipment. You called it out: in the turbine world in particular, there are more upfront or progress payments relative to our compression business. In the recip world, it remains to be seen where it all lands; those are key variables we are working through as we talk to our channel partners or OEMs.
As we think about paying for it, protecting the balance sheet—and therefore the overall franchise—is really important to us. We have our 4.0x leverage target; we are about there right now. When we went public, we were 4.2x leverage and made a commitment we would get it down to 3.5x by 2025, and we did, on target. As we commence this investment cycle, we have been transparent that you should expect us to drift above our 4.0x long-term leverage target, but only periodically, as we build out the foundation. Then, as the contracts come in, the combination of the compression and power businesses will start to delever quickly and get us into target and then some.
We also have this incredible compression business that is extremely resilient, with extremely limited exposure to near-term moves in commodity prices, and it has performed really well in big stress tests like COVID. We have a wonderful ABL and terrific bank groups that support us, and we have executed really well on three bond offerings in the last couple of years, including the first 10-year bond in the compression business. We have a great business, experienced team, and a multitude of options to fund the business going forward.
Mickey McKee: Yes, and Doug, you hit on the fact that there are some advance progress payments due on some of these bigger turbines. We are highly focused on that and on leveraging our existing relationships with our OEMs and vendors to minimize the impact of those progress payments.
Douglas Baker Irwin: Got it. Thanks for the time.
John Griggs: Thanks, Doug.
Operator: Thank you. Our next question comes from the line of Neal Dingmann with William Blair. Please proceed with your question.
Neal Dingmann: Good morning, guys. Nice update and great quarter again. My first question, Mickey, maybe for you or John, on compression M&A: could you talk to future compression horsepower purchase-leaseback potential? Based on my E&P conversations, it sounds like there are several E&Ps that would be willing or wanting to transfer ownership to you all given your service record. How active are those discussions, and what type of potential do you see there?
Mickey McKee: Hey, good morning, Neal. I think there is a lot of opportunity there. We are, as John said, in the middle of this investment cycle in power and we are very focused on that, but we are also going to take advantage of opportunistic things that pop up on the compression side, too, such as purchase-leasebacks. We executed one last quarter, just over a 20,000-horsepower package, which was a really nice, bite-sized deal for us to digest easily. That has gone very smoothly with us taking over operations on April 1. We love those deals and want to look at more of them going forward. As those opportunities come up, we will take advantage of them.
Neal Dingmann: I think that is big. And then secondly, on the services side, would the existing workforce service both compression and power? Do you have enough folks in place now to service what you have, or are you continually adding some folks?
Mickey McKee: We are always adding folks and putting them through our training program—it is a world-class program. We are opening up our new facility in Midland, and we will move in the June timeframe. It is going to be a great resource for us to continue to train our people and also our customers’ people so they can be around our equipment safely. We focus on the training aspect of our workforce as much or more than anybody in our industry, and it is a real differentiator. As for technicians right now, we are pretty fully staffed and continuing to add to handle our growth.
We are adding new training programs into our Bears Academy for power and electrical topics, working with several of our OEMs and equipment providers to provide training programs at our facility. We are also arming them with our technology—we are rolling out large language models and AI agentic tools in the second half of the year to help with parts locations, troubleshooting, and other tasks. That will be a tremendous asset to our employees.
John Griggs: Thanks, Mickey. Thanks, Neal.
Operator: Thank you. Our next question comes from the line of Analyst with Bank of America. Please proceed with your question.
Analyst: Was wondering if we could go back to the contracts and how you are securing contracts for the incremental megawatts you are purchasing. Is it mostly pre-contracted, or is there some on-spec ordering for some of the future megawatts? Thanks.
Mickey McKee: Good morning. We are having to go out and look for this equipment on the power side and make commitments. I would not characterize it as speculative CapEx as much as educated commitments. We are looking at our backlog of opportunities that DPS brought to the table as well as additional inbounds since we closed the deal. We are in pretty advanced conversations on many of those for contracts to be put in place over the next several months. We are ordering equipment based on the visibility we have on the pipeline, and we expect contracts to roll in, hopefully, pretty quickly.
Analyst: Great. That makes sense. Following up, on the Compression Infrastructure margins—you are already above 70% in the first quarter. The new guide is up a little bit, but could you talk about the rest of the year and what we should expect? Could that 70% creep higher given where 1Q has been?
John Griggs: I am glad you called that out. We are really happy to see that number. 70.6% in the first quarter was really gangbusters for us. Compression is hitting on all cylinders. We attribute so much of that to three things: investments in our people and technology over the last two years are paying off—things are breaking less, we are spending more smartly, and we are more productive; continuing to drive toward larger horsepower; and pricing.
In terms of the guide being a little below where we came out in the quarter, maybe there is an element of conservatism, but with oil prices being high, that drives lube oil and fuel prices high, and those are two inputs in our cost of goods sold. Given the unpredictability, we felt the guide range is the right place to be.
Operator: Our next question comes from the line of Theresa Chen with Barclays. Please proceed with your question.
Theresa Chen: Good morning. Thank you for taking my questions. On the base business, Mickey, now that you are seeing over three years of lead time and that metric has only moved one direction since your IPO, when you think about pricing power at this point—and to your earlier comments about pricing power continuing into 2027 and beyond—what are you seeing in terms of price increases across the industry, and what do you anticipate over the next couple of years as a result of the supply tightness? Taking a step back, do you think the situation is sustainable? How does the industry solve this supply crunch, if it does, and how do you see the landscape evolving as a result?
Mickey McKee: Good morning, Theresa. Good questions. I think pricing on our equipment is going to continue to move up. How much and how far will depend on external factors like the price of oil, competitive landscape, and other dynamics. We have the opportunity to continue the strong pricing we have seen over the last several years. New units are continuing to come out the door and be priced at spot rates that are very constructive for us. We are continuing to be able to reprice the base fleet at some increases as contracts roll over. As I mentioned, producers and midstreamers are willing to lock in equipment for longer periods of time now, which is wonderful for our base business.
As for the supply crunch, I think demand will continue to outstrip supply. Lead times continue to extend. There is an increasing amount of compression moving away from electric due to access-to-grid challenges. I think there will continue to be a supply shortage in the industry for the foreseeable future, especially with increasing GORs in the Permian Basin and increased takeaway capacity allowing additional growth. We are excited about the Permian as well as other basins, and we think there will be continued, incredible demand for our services and our equipment.
Theresa Chen: Thank you. That is helpful. On the Power Infrastructure side, separate from the earlier question about contract duration and terms with data center counterparties, how do you think about counterparty credit risk in these contracts? And how much terminal value is embedded in your 15% unlevered return targets?
John Griggs: Great question. I will answer the terminal value one first—it depends on the project and duration. If we are penciling in a 15-year contract, we will have a zero terminal value. Even if you put a lot of terminal value in there, it does not make much difference over that timeframe. If it was a seven-year contract, you get a different answer. We need to feel really good that we are going to be in that upper-teens dynamic when we enter into any contracts. On counterparty credit risk, it is mission critical. In compression, we have been fortunate to see a lot of our counterparties get acquired by some of the largest players in the energy complex—more investment-grade customers.
We think the opportunity set is there on the digital infrastructure side too; it is just a much wider marketplace in terms of participants owning, building, and developing data centers or being the underlying customers. Each contract will be a little different, but we will definitely bake credit considerations into our decisions on which contracts to pursue and which ones we let somebody else grab.
Theresa Chen: Thank you.
Graham Sones: Thanks, Theresa.
Operator: Thank you. Our next question comes from the line of Sebastian Erskine with Rothschild and Co. Redburn. Please proceed with your question.
Sebastian Erskine: Hey, good morning, gentlemen, and congrats on the developments today. Very exciting. First question: in your conversations with customers, one of the advantages with compression has been that equipment tends to stay on for many years even beyond the initial contract term. Are more of your customers thinking about distributed power as a bridging solution until the grid catches up, or is there scope for this to be used as a permanent turnkey utility-type offering for these hyperscalers?
Mickey McKee: Good morning, Sebastian. Typical contract term we are talking about with these data centers is 10 or 15 years, and many want the option to extend at the end. This business has evolved from being seen as a bridge to grid interconnection to increasingly being viewed as a permanent power supply, depending on regulatory developments. Many in this business today are looking at permanent solutions and want to make sure it is right for the long term. Increasingly, we are hearing timelines move from six to eight years to grid interconnection to now outside of a decade to maybe never. We view this as permanent digital and power infrastructure that will be there for a very long period of time.
Sebastian Erskine: Really appreciate the color. On the margins, 60% to 70% adjusted gross margins for the Power Infrastructure business—John, you mentioned a large range to begin with. Could you talk through the drivers behind that and the scope for margin progression over the medium term? Is the focus predominantly on just getting the top line?
John Griggs: It is always going to be focused on return on capital at the end of the day. We guided that way for a couple of reasons. Number one, we have only owned the business for five weeks. We have transferred their business into our ERP system, as Mickey mentioned, but we just wanted to protect ourselves from any surprises. Number two, the DPS business we bought was somewhat capital-starved. They had a neat long-term primary power contract with a data center and were getting traction on contract number two, but they did not have access to more power.
The management team there purposefully kept a lot of their contracts shorter term with the idea that if they could land the 100 to 200-plus megawatt long-term quality opportunity, they could then roll off what they had on short term into that. That is what we inherited. As we invest to build our foundation of power, we do have a lot of power that will stay on short-term contracts, and we want to leave some on short-term so we can pull it off once we grab the longer-term contracts Mickey has talked about. We would be unwise to adjust our cost structure or workforce for what would be a temporary move when we know a longer-term contract is coming.
That causes us to keep a wide range. As we get to scale and have more power, it is our view that the range will narrow and be more similar to the compression business.
Sebastian Erskine: Really appreciate that, John, and congrats on the results today. Excited for the growth. Thanks very much.
John Griggs: Thanks, Sebastian.
Operator: Thank you. Our next question comes from the line of Analyst with RBC Capital Markets. Please proceed with your question. Your line is live.
Analyst: Hi, sorry. Good morning. On the power side, can you talk a little bit about the cash conversion cycle? What are the timelines from when you sign a contract—assuming you have the equipment—to when you start generating revenues?
Mickey McKee: Good morning. That will depend on the contract. You will see some opportunities for less sophisticated installations to be in the three- to six-month timeframe from procuring equipment to generating revenues. For larger plants, it could be longer—maybe six to 12, maybe 18 months. That will be determined based on the contracts we execute.
Analyst: Okay. Great. Thank you. Are most of the discussions you are having on the power side in Texas? And related to that, can the compression and power businesses share technician pools or operations to drive efficiencies?
Mickey McKee: We are seeing a lot of inbounds and opportunities in Texas, but also across the United States. Right now, we are keeping the operations groups separated so that they can focus on either power or compression. As we develop and have projects in close proximity to our compression operations, there will definitely be some overlap where they can support each other, especially on operations support like supply chain and safety. We think there will be some overlap, but for now we are keeping them separated as we build out and determine where the efficiencies come from.
Analyst: Got it. Great. Thank you very much.
John Griggs: Thanks.
Operator: Our final question this morning comes from the line of Analyst with Daniel Energy Partners. Please proceed with your question.
Analyst: Good morning. Thanks for squeezing me in. First one is on the purchase-leaseback transaction. Maybe you could talk through that a little bit more and discuss if there is more interest in transactions like that today on both your side and the operator, given the tightness in the market and for a lot of operators it is not really a core operation for them. How do they think through service quality and things of that nature? Maybe you could elaborate on that a bit more.
Mickey McKee: Good morning. The purchase-leaseback we executed was a really good deal for us, and we think it is a great deal for the customer too. It is not a core competency for many customers to own and operate their own compression. We have the back office and infrastructure built to do that every day and focus on service. There are a lot of advantages for a customer to execute a transaction like that. We do think there are opportunities for additional transactions like these to come to fruition.
Analyst: Thanks for that. And in addition to the engine lead times, you made a comment highlighting the importance of capacity where the units are actually being packaged. Could you share anything on that front—how tight space is today and your thoughts?
Mickey McKee: Yes. That is something we have to pay very close attention to—shop capacity and the ability to put these things together once you get the engine and the compressor for these units. We marry the two as we secure engines, making sure our packagers have ample shop space and capacity. You are looking at something similar to engine deliveries, because they are booking shop space as they get engines and orders coming in. Their lead times are in the same ballpark as engine lead times—excess of three years out, booked up and shop space allocated to build compressors. We are making sure we have that supply procured as well as the engines, to ensure all long-lead, critical-path items are secured.
Analyst: Understood. Thank you for taking my questions.
John Griggs: Thanks.
Operator: Thank you. Ladies and gentlemen, that concludes our question and answer session. I will turn the floor back to Mr. McKee for any final comments.
Mickey McKee: Thanks, and thank you to everyone participating in today's call. We look forward to speaking with you again after we report our results for the second quarter.
Operator: Thank you. This concludes today's conference. You may disconnect your lines at this time. Thank you for your participation.
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- Merck Stock Down 7% in a Month: Should Investors Hold or Exit?
May 11, 2026
Merck’s MRK stock has declined 7.3% in the past month despite announcing a solid first-quarter 2026 report on April 30. Merck beat estimates for both earnings and sales. Total revenues rose 5% to $16.3 billion, helped by strong growth from Keytruda and Winrevair. However, the company incurred a loss of $1.28 per share in the quarter due to a one-time charge of $3.62 per share related to the acquisition of Cidara, which closed in the first quarter. Even though the acquisition will benefit the company in the long run, a reported loss can limit investor optimism. The company also slightly raised its sales range, which may have been below investor expectations.
Also, in late April, the company faced a pipeline setback, which resulted in the stock’s recent sell-off. Merck and Eisai’s phase III LITESPARK-012 study evaluating two triplet combinations of blockbuster PD-L1 inhibitor, Keytruda plus Lenvima, failed to meet its main goals in previously untreated patients with advanced clear cell renal cell carcinoma, a common form of kidney cancer.
However, a single quarter’s results are not so important for long-term investors to make an investment decision. Let’s understand the company’s strengths and weaknesses to better analyze how to play Merck stock in the post-earnings scenario.
Keytruda: Merck’s Biggest Strength
Merck boasts more than six blockbuster drugs in its portfolio, with Keytruda being the key top-line driver. Keytruda, approved for several types of cancer, alone accounts for around 55% of the company’s pharmaceutical sales. Keytruda now holds 44 FDA-approved indications spanning 19 tumor types, along with two tumor-agnostic approvals.
The drug has played an instrumental role in driving Merck’s steady revenue growth over the past few years. Keytruda recorded sales of $8.0 billion in the first quarter of 2026, up 8% year over year.
Keytruda sales are gaining from continued strong momentum in metastatic indications and rapid uptake across earlier-stage launches. The company expects the growth to continue till it loses patent exclusivity in 2028.
Merck is working on different strategies to drive Keytruda's long-term growth. These include innovative immuno-oncology combinations, including Keytruda with LAG3 and CTLA-4 inhibitors. In partnership with Moderna MRNA, Merck is developing a personalized mRNA therapeutic cancer vaccine called intismeran autogene (V940/mRNA-4157) in combination with Keytruda in pivotal phase III studies for earlier-stage and adjuvant NSCLC and adjuvant melanoma.
Merck expects Keytruda to achieve peak sales of $35 billion by 2028. Merck’s other oncology drugs, Welireg, AstraZeneca (AZN)-partnered Lynparza and Eisai-partnered Lenvima, are also contributing to top-line growth.
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Merck’s Animal Health business is also a key contributor to its top-line growth, with sales expected to more than double by mid-2030s.
MRK’s Pipeline Progress & Recent M&A Spree
Merck’s expanding drug pipeline and potential new blockbuster drugs beyond Keytruda look encouraging.
Its phase III pipeline has almost tripled since 2021, supported by in-house pipeline progress as well as the addition of candidates through M&A deals. Merck expects to launch 20 new drugs by 2030, with many already launched.
Some key new products with blockbuster potential are its 21-valent pneumococcal conjugate vaccine, Capvaxive, and pulmonary arterial hypertension drug, Winrevair. Both products have witnessed a strong launch and have the potential to generate significant revenues over the long term.
Merck’s RSV antibody, Enflonsia (clesrovimab), was approved in the United States in June 2025 and in the EU in April 2026. A once-daily, single-tablet two-drug regimen of doravirine and islatravir, Idvynso, was approved in the United States for virologically suppressed HIV-1 in April 2026.
Merck has other promising candidates in its late-stage pipeline, such as enlicitide decanoate/MK-0616, an oral PCSK9 inhibitor for hypercholesterolemia, tulisokibart, a TL1A inhibitor for ulcerative colitis and Daiichi-Sankyo-partnered antibody-drug conjugates.
Merck has been on an acquisition spree in the past year, as it faces the looming patent expiration of Keytruda in 2028. The acquisition of Verona in 2025 added Ohtuvayre, a novel, first-in-class maintenance treatment for chronic obstructive pulmonary disease, with multibillion-dollar commercial potential. Ohtuvayre's commercial launch is off to a solid start.
In January 2026, Merck acquired Cidara Therapeutics, which added its lead pipeline candidate, MK-1406 (formerly CD388), a first-in-class long-acting, strain-agnostic antiviral agent, currently being evaluated in late-stage studies for the prevention of seasonal influenza in individuals at higher risk of complications.
In April 2026, it acquired California-based cancer biotech, Terns Pharmaceuticals, which added Terns’ lead chronic myeloid leukemia candidate, TERN-701, a novel oral allosteric inhibitor of the BCR::ABL oncogene, to Merck’s hematology/cancer pipeline. Merk believes TERN-701 has multibillion-dollar commercial potential.
Declining Sales of MRK’s Gardasil & Other Vaccines
Sales of Merck’s second-largest product, its HPV vaccine, Gardasil, plunged 22% to $1.07 billion in the first quarter due to continued weak sales performance in China. Sales of Gardasil are declining in China due to weak demand trends amid an economic slowdown. The company is also seeing lower demand for the vaccine in Japan. Gardasil sales are not expected to improve in 2026.
Sales of some other Merck vaccines, like Proquad, M-M-R II, Varivax, Rotateq and Vaxneuvance, also declined in the first quarter.
MRK’s Keytruda Faces Patent Expiration in 2028
Merck is heavily reliant on Keytruda. Though Keytruda may be Merck’s biggest strength and a solid reason to own the stock, the company is excessively dependent on the drug. Keytruda’s core U.S. patent is expected to expire around 2028, with additional patents expiring slightly after that. Keytruda is expected to face significant biosimilar competition around 2028-2029. Once biosimilars enter, Keytruda’s sales are likely to decline sharply.
Also, competitive pressure might increase for Keytruda in the near future from dual PD-1/VEGF inhibitors that inhibit both the PD-1 pathway and the VEGF pathway at once. They are designed to overcome the limitations of single-target therapies like Keytruda.
MRK’s Generic Headwinds in 2026
MRK is seeing declining demand for its diabetes products (Januvia/Janumet) and the generic erosion of some drugs like Isentress/Isentress HD and Bridion in the European Union and Dificid in the United States. Bridion is expected to lose patent exclusivity in the United States in July 2026, and sales are expected to significantly decline thereafter. Sales of Januvia/Janumet are expected to decline steeply from 2026 onward due to government price setting, an anticipated patent expiry in 2026 and ongoing competitive pressure.
In 2026, Merck expects generic competition for Januvia/Janumet, Bridion and Dificid to hurt revenues by approximately $2.5 billion.
MRK Share Price, Valuation & Estimates
Merck’s shares have risen 38.4% in the past year compared with an increase of 17.3% for the industry. The stock has also outperformed the sector as well as the S&P 500 index.
Merck Stock Outperforms Industry, Sector & S&P 500Zacks Investment Research
Image Source: Zacks Investment Research
From a valuation standpoint, Merck looks slightly expensive. Going by the price/earnings ratio, the company’s shares currently trade at 16.79 forward earnings, slightly higher than 16.40 for the industry. The stock is also trading above its 5-year mean of 12.70. However, the stock is cheaper than other drugmakers like Eli Lilly LLY and J&J JNJ.
MRK Stock ValuationZacks Investment Research
Image Source: Zacks Investment Research
Estimates for MRK’s 2026 earnings have risen from $4.87 to $4.88 per share over the past 30 days, while those for 2027 have declined from $9.85 per share to $9.77 per share.
MRK Estimate MovementZacks Investment Research
Image Source: Zacks Investment Research
Stay Invested in MRK Stock
Merck has one of the world’s best-selling drugs in its portfolio, generating billions of dollars in revenues. Though Keytruda will lose patent exclusivity in 2028, its sales are expected to remain strong until then. Merck’s new products, Winrevair, Welireg and Capvaxive, key pipeline progress and expansion of its respiratory and infectious disease and oncology portfolios through the acquisitions of Verona Pharma, Cidara Therapeutics and Terns Pharmaceuticals have improved its long-term growth prospects.
Merck expects over $70 billion of potential non-risk-adjusted commercial opportunity for the current pipeline by the mid-2030s. This estimate is more than double the peak consensus sales estimate for Keytruda of $35 billion in 2028. Merck said that the estimate of $70 billion was $20 billion higher than what they expected just one year ago.
The new products and strong progress in its pipeline have increased confidence that Merck may be able to maintain growth even after Keytruda loses exclusivity.
However, Merck faces several near-term challenges, including persistent challenges for Gardasil in China, potential competition for Keytruda, and rising competitive and generic pressure on some of its drugs. Also, estimates have declined recently due to costs related to its various M&A deals.
Long-term investors may continue retaining this Zacks Rank #3 (Hold) stock and see how the company manages its future product and pipeline growth and replaces Keytruda revenues. However, short-term investors may reduce their position in the stock as there seems to be limited prospects for growth in the near term. You can see the complete list of today’s Zacks #1 Rank (Strong Buy) stocks here.
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- Moody’s cuts Wabash rating third time in a year, execs eye ‘27 rebound
May 11, 2026
Trailer manufacturer Wabash National had its debt rating downgraded by Moody’s for the third time in a year, almost to the day, while executives on a company earnings call with analysts a few days earlier tried to make a case for a turnaround that would start next year.
The latest Moody’s move, announced May 5, is a downgrade of its corporate family rating to B3 from B2. Moody’s downgraded Moody’s to B1 on May 7, 2025 and then to B2 on November 5.
Meanwhile, S&P Global Ratings cut the Wabash debt rating to B+ in May of last year and B soon after Moody’s (NYSE: MCO) made its move to B2 in November. That latest rating for Wabash is still in effect at S&P Global. The B rating at S&P Global Ratings (NYSE: SPGI) is considered a notch above Wabash’s B3 grade at Moody’s.
The B3 rating at Moody’s is six notches below the cutoff line between investment grade and non-investment grade debt.
‘Very weak’ credit metrics
“The rating downgrade reflects our expectation that Wabash’s credit metrics will remain at very weak, unsustainable levels over the next 12 months,” Moody’s said in its report. “Wabash’s earnings have evaporated and cash burn has persisted during a prolonged down cycle in new truck trailer production as the company’s customers defer investments in their transportation fleets.”
Moody’s said trailer production at Wabash (NYSE: WNC) should increase sequentially during the year, though the latest quarterly data continues a long slide.
Wabash data on trailers shipped has been declining steadily for many months. It was 5,378 in the first quarter, down from 5,901 in the fourth quarter of 2025. Its recent high-water mark was 13,670 in the third quarter of 2022.
Financial measures have also been grim at Wabash. It reported cash and cash equivalents on hand at $31.9 million at the end of 2025. A year earlier, it was $144.5 million. At the end of 2022, cash and cash equivalents were $58.2 million.
Net sales in its Transportation Solutions segment, which includes its truck manufacturing operations, were $250.1 million in the first quarter of 2026. Sequentially, that is less than the $262.9 million in the fourth quarter of 2025.
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In the third quarter of 2022, Transportation Solutions reported net sales in Transportation Solutions of $611.8 million.
Wabash’s net income last year was impacted positively by the settlement of the nuclear verdict it faced in Missouri. But more reflective of its operations, the company posted a gross profit of $69.9 million in 2025 for all operations, down from $265 million a year before. In 2022, gross profit was $322.7 million.
Company seeing ‘early stabilization’
In Wabash’s first quarter earnings call, when the company posted an operating loss of $37.3 million in its Transportation Solutions segment, which contains its trailer manufacturing activities, CEO Brent Yeagy acknowledged the poor performance but sought to forecast better days.
“Order patterns were uneven, asset utilization inconsistent and capital decisions across the industry were being evaluated carefully,” he said. “At the same time, we were encouraged by early signs of stabilization and improving fundamentals that typically precede a broader recovery. Now as we move into the second quarter of 2026, both our customers and our visibility continues to improve. And it shows an environment that is building the set up for a constructive 2027 as spot rates, contract rates, capacity and demand, all are coming together and drive back to replacement demand for equipment and possibly beyond as fleets begin to plan more confidently.”
Wabash is not followed closely by equity analysts; only one was on the earnings call.
Rising backlog
Yeagy said the company’s backlog in the quarter was $837 million, which was up 19% from the fourth quarter of 2026. He added it was the highest quarter-to-quarter gain in backlog growth for the first quarter in the company’s history .
Even with an improvement in market conditions, Moody’s said it still expects Wabash’s debt/EBITDA ratio to be 6X at the end of 2027 “though trending in a positive direction.” The agency said it expects free cash flow to remain negative, “as the company’s working capital needs to support growth outweigh the recovery in earnings.”
Moody’s also said at the end of 2023, that ratio was 1X.
The debt issue also was raised in terms of Wabash’s short term needs. Moody’s said Wabash has “adequate liquidity to bridge the company to what we expect will be a meaningfully improved production environment in 2027.”
But it’s going to need to rely more on a $350 million asset-based revolving credit facility, Moody’s said. That ABL expires in September 2027, “which introduces refinancing risk in the near-term.”
Moody’s added that it expects Wabash’s revenue would be “slightly down in 2026, with negative earnings and free cash flow.”
Wabash’s stock is only down 9.37% in the last 52 weeks. But the more recent trends have been brutal: down 17.58% in the last month and 31.55% in the last year. According to Yahoo Finance, its five-year rate of return exceeds negative 58%.
Wabash declined comment on the Moody’s rating change.
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The post Moody’s cuts Wabash rating third time in a year, execs eye ‘27 rebound appeared first on FreightWaves.
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- Kodiak Gas Services Reports First Quarter 2026 Financial Results, Increases Full Year 2026 Guidance to Include Distributed Power Business and Provides Power Generation Capacity Update and Growth Outlook
May 11, 2026
THE WOODLANDS, Texas, May 11, 2026--(BUSINESS WIRE)--Kodiak Gas Services, Inc. (NYSE: KGS) ("Kodiak" or the "Company") today reported financial and operating results for the quarter ended March 31, 2026. The Company announced increased full-year 2026 guidance to incorporate the contribution from the recently-closed acquisition of Distributed Power Solutions, LLC (DPS). Kodiak also announced that it has procured over 260 megawatts (MWs) of additional power generation capacity and expects annual growth of 300 to 500 MWs per year through 2030.
First Quarter 2026 and Recent Highlights
Record Contract Services segment revenues of $307.0 million Contract Services gross margin percentage of 48.2% and adjusted gross margin percentage(1) of 70.6% Net income of $17.8 million, or $0.20 per diluted share and adjusted net income(1) of $52.0 million, or $0.59 per adjusted diluted share(1) Record adjusted EBITDA(1) of $190.1 million, a 7.0% increase compared to first quarter 2025 Quarterly net cash provided by operating activities of $71.2 million and record discretionary cash flow(1) of $126.5 million, a 9.0% increase compared to first quarter 2025 Completed 20,700 horsepower purchase-leaseback transaction with a leading oil and gas producer in the Permian Basin Issued $1 billion of senior unsecured notes, reducing the Company's weighted average borrowing rate and bolstering liquidity Closed the acquisition of DPS on April 1, 2026 and procured over 260 MWs of additional power generation capacity; expect to take delivery of 61 MWs in 2026 with the balance to be delivered in 2027 through 2029
2026 Guidance Highlights
Provided revised full year 2026 guidance to reflect continued strength in natural gas compression and to incorporate new power segment Increased 2026 Adjusted EBITDA guidance to a range of $820 million to $860 million
CEO Commentary
"Kodiak is off to a fantastic start in 2026, with record contract services revenue and adjusted gross margin percentage driving record quarterly adjusted EBITDA. Our contract compression business continues to outperform expectations, and our new power business has tremendous growth potential," said Mickey McKee, Kodiak's President and Chief Executive Officer. "Since closing the DPS acquisition, we have been actively engaged with numerous data center developers discussing the scope and scale of their distributed power needs. Given the overwhelming demand, we are actively working to scale our power offerings, including today's announcement of equipment orders that will significantly increase our power generation capacity to over 650 megawatts, and clear line of sight to over two gigawatts by the end of the decade. We are currently in advanced discussions with customers to deploy this capacity under long-term contracts.
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"We remain constructive on the outlook for U.S. natural gas, with rising demand driving the need for incremental compression infrastructure. The market remains tight with historically long lead times for new large horsepower compression, but Kodiak is well positioned to deliver on our growth targets in the coming years. We're also encouraged by the increasing adoption of distributed power as the preferred solution for data center and other large industrial power consumers' long-term power needs. We have a robust pipeline of commercial opportunities, and have made meaningful progress to secure the equipment to allow us to capture those opportunities and realize our long-term growth objectives."
(1) Adjusted gross margin percentage, adjusted net income, adjusted diluted earnings per share, adjusted EBITDA, and discretionary cash flow are non-GAAP financial measures. Definitions and reconciliations to the most comparable GAAP financial measure are included herein.
Segment Information
Contract Services segment revenue was $307.0 million in the first quarter of 2026, a 6.2% increase compared to $289.0 million in the first quarter of 2025. Contract Services segment gross margin was $148.0 million in the first quarter of 2026, an 18.3% increase compared to $125.2 million in the first quarter of 2025 and adjusted gross margin was $216.7 million in the first quarter of 2026, a 10.7% increase compared to $195.7 million in the first quarter of 2025.
Other Services segment revenue was $38.8 million in the first quarter of 2026, a 4.7% decrease compared to $40.7 million in the first quarter of 2025. Other Services segment gross margin and adjusted gross margin were each $6.2 million in the first quarter of 2026, a 12.7% increase compared to $5.5 million for each measure in the first quarter of 2025.
Financial Results
Net income attributable to common shareholders of $17.8 million or $0.20 per share, in the first quarter of 2026 included a $36.5 million loss on extinguishment of debt related to the refinancing of the Company's senior notes due 2029, as well as $8.3 million of nonrecurring transaction expenses related primarily to the acquisition of DPS. Adjusting for these items and the associated tax effects, adjusted net income was $52.0 million or $0.59 per diluted share.
Long-Term Debt and Liquidity
Total debt outstanding was $2.8 billion as of March 31, 2026, and the Company had $1.5 billion available on its ABL Facility. Kodiak’s credit agreement leverage ratio was 3.6x for the first quarter of 2026.
Summary Financial Data
Three Months Ended (in thousands, excluding percentages) March 31, 2026 December 31,
2025 March 31, 2025 Total revenues $ 345,759 $ 332,871 $ 329,642 Net income attributable to common shareholders $ 17,805 $ 24,625 $ 30,411 Adjusted net income (1) $ 52,001 $ 35,261 $ 32,637 Adjusted EBITDA (1) $ 190,092 $ 184,451 $ 177,664 Adjusted EBITDA percentage (1) 55.0 % 55.4 % 53.9 % Contract Services revenue $ 306,985 $ 301,810 $ 288,956 Contract Services adjusted gross margin (1) $ 216,726 $ 208,911 $ 195,721 Contract Services adjusted gross margin percentage (1) 70.6 % 69.2 % 67.7 % Other Services revenue $ 38,774 $ 31,061 $ 40,686 Other Services adjusted gross margin (1) $ 6,155 $ 3,961 $ 5,460 Other Services adjusted gross margin percentage (1) 15.9 % 12.8 % 13.4 % Maintenance capital expenditures $ 17,758 $ 22,265 $ 16,407 Growth capital expenditures (2) (3) $ 85,552 $ 25,253 $ 55,983 Other capital expenditures (4) 7,458 11,895 22,258 Total Growth and Other capital expenditures $ 93,010 $ 37,148 $ 78,241 Discretionary cash flow (1) $ 126,505 $ 112,524 $ 116,084 Free cash flow (1) $ 36,962 $ 78,609 $ 47,219
(1) Adjusted net income, adjusted EBITDA, adjusted EBITDA percentage, adjusted gross margin, adjusted gross margin percentage, discretionary cash flow and free cash flow are non-GAAP financial measures. For definitions and reconciliations to the most directly comparable financial measures calculated and presented in accordance with GAAP, see "Non-GAAP Financial Measures" below. (2) Growth capital expenditures for the three months ended March 31, 2026 include $18.0 million for additional power generation capacity. (3) Growth capital expenditures made to (1) expand the operating capacity or operating income capacity of assets including, but not limited to, the acquisition of additional compression units, upgrades to existing equipment, expansion of supporting infrastructure, and implementation of new technologies, (2) maintain the operating capacity or operating income capacity of assets by acquisition of replacement compression units and their supporting infrastructure, and (3) expand the operating capacity or operating income capacity of existing assets.. (4) Other capital expenditures made on assets required to support our operations—such as rolling stock, leasehold improvements, technology hardware and software and related implementation expenditures, safety enhancements to equipment, and other general items that are typically capitalized and that have a useful life beyond one year.
Summary Operating Data
(as of the dates indicated)
March 31, 2026 December 31,
2025 March 31, 2025 Fleet horsepower (1) 4,477,398 4,456,285 4,422,914 Revenue-generating horsepower (2) 4,389,412 4,354,724 4,284,103 Fleet compression units 4,670 4,736 4,941 Revenue-generating compression units 4,494 4,490 4,545 Revenue-generating horsepower per revenue-generating compression unit (3) 977 970 943 Fleet utilization (4) 98.0 % 97.7 % 96.9 %
(1) Fleet horsepower includes (x) revenue-generating horsepower and (y) idle horsepower, which is comprised of compression units that do not have a signed contract or are not subject to a firm commitment from our customer and therefore are not currently generating revenue. (2) Revenue-generating horsepower includes compression units that are operating under contract and generating revenue and compression units which are available to be deployed and for which we have a signed contract or are subject to a firm commitment from our customer. (3) Calculated as (i) revenue-generating horsepower divided by (ii) revenue-generating compression units at period end. (4) Fleet utilization is calculated as (i) revenue-generating horsepower divided by (ii) fleet horsepower.
Full-Year 2026 Guidance
Kodiak is providing revised guidance for the full year 2026. The full year 2026 guidance below incorporates three quarters of the financial impact of the DPS acquisition given the April 1, 2026 closing date.
Full-Year 2026 Guidance (in thousands, excluding percentages) Low High Adjusted EBITDA (1) $ 820,000 $ 860,000 Discretionary cash flow (1)(2) $ 520,000 $ 570,000 Segment Information Compression Infrastructure (3) revenue $ 1,250,000 $ 1,280,000 Compression Infrastructure adjusted gross margin percentage (1) 68.5 % 70.0 % Power Infrastructure (3) revenue $ 95,000 $ 125,000 Power Infrastructure adjusted gross margin percentage (1) 60.0 % 70.0 % Other Services revenue $ 125,000 $ 160,000 Other Services adjusted gross margin percentage (1) 13.0 % 16.0 % Capital Expenditures Maintenance capital expenditures $ 80,000 $ 90,000 Growth capital expenditures: Compression Infrastructure (3) $ 245,000 $ 275,000 Power Infrastructure (3) 400,000 500,000 Total Growth capital expenditures $ 645,000 $ 775,000 Other capital expenditures $ 45,000 $ 55,000 Total Growth and Other capital expenditures $ 690,000 $ 830,000
(1) The Company is unable to reconcile projected adjusted EBITDA to projected net income (loss) and discretionary cash flow to projected net cash provided by operating activities and projected adjusted gross margin percentage to projected gross margin percentage, the most comparable financial measures calculated in accordance with GAAP, respectively, without unreasonable efforts because components of the calculations are inherently unpredictable, such as changes to current assets and liabilities, unknown future events, and estimating certain future GAAP measures. The inability to project certain components of the calculation would significantly affect the accuracy of the reconciliations. (2) Discretionary cash flow guidance assumes no change to Secured Overnight Financing Rate futures. (3) The Company's Contract Services segment will be renamed Compression Infrastructure going forward. In addition, the Company intends to create a new Power Infrastructure segment that will include a significant majority of the assets, revenues and expenses acquired in the DPS acquisition, as well as similar assets, revenues and expenses, going forward. A portion of the revenues and expenses acquired in the DPS acquisition that are not recurring in nature, as well as similar revenues and expenses arising from the power business going forward, will be included in the Company's existing Other Services segment. To assist in comparisons to future segment results, the guidance above is provided using the Company's go-forward segment structure.
Conference Call
Kodiak will conduct a conference call on Monday, May 11, 2026, at 11:00 a.m. Eastern Time (10:00 a.m. Central Time) to discuss financial and operating results for the quarter ended March 31, 2026. To listen to the call by phone, dial 877-407-4012 and ask for the Kodiak Gas Services call at least 10 minutes prior to the start time. To listen to the call via webcast, please visit the Investors tab of Kodiak’s website at www.kodiakgas.com.
About Kodiak
Kodiak is a leading contract compression, distributed power and energy infrastructure services provider in the United States. The Company serves as a critical link in the infrastructure chain that enables the safe, reliable and efficient production of energy. Headquartered in The Woodlands, Texas, Kodiak provides contract compression, distributed power and related services to oil and gas producers, midstream customers and digital infrastructure operators. Additional information is available on the Company's website at www.kodiakgas.com.
Non-GAAP Financial Measures
Adjusted net income and adjusted earnings per share are considered non-GAAP measures. Adjusted net income is defined as net income adjusted to exclude certain items, as applicable, such as (i) impairment of long-lived assets; (ii) severance expenses; (iii) transaction expenses; (iv) sales tax reserve; (v) loss on disposal of business; (vi) loss (gain) on derivatives; (vii) loss on extinguishment of debt; and (viii) the tax effects of the adjustments. Adjusted earnings per share is calculated by dividing adjusted net income by the weighted average diluted shares outstanding.
Adjusted EBITDA and adjusted EBITDA percentage are considered non-GAAP measures. Adjusted EBITDA is defined net income before interest expense; income tax expense; and depreciation and amortization; plus certain items, as applicable, such as (i) impairment of long-lived assets; (ii) loss (gain) on derivatives; (iii) equity compensation expense; (iv) severance expenses; (v) transaction expenses; (vi) sales tax reserve; (vii) loss (gain) on disposal of business; (viii) loss (gain) on sale of assets; and (ix) loss on extinguishment of debt. We define adjusted EBITDA percentage as adjusted EBITDA divided by total revenues.
Adjusted net income, adjusted diluted EPS, adjusted EBITDA and adjusted EBITDA percentage are used as supplemental financial measures by our management and external users of our financial statements, such as investors, commercial banks and other financial institutions, to assess: (i) the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets; (ii) the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities; (iii) the ability of our assets to generate cash sufficient to make debt payments and pay dividends; and (iv) our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure. We believe adjusted net income, adjusted diluted EPS, adjusted EBITDA and adjusted EBITDA percentage provide useful information because, when viewed with our GAAP results and the accompanying reconciliation, they provide a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business. Reconciliations of adjusted net income and adjusted EBITDA to net income and adjusted diluted EPS to GAAP diluted earnings per share, the most directly comparable GAAP financial measures are presented below.
Adjusted gross margin is defined as revenue less cost of operations, exclusive of depreciation and amortization expense. Adjusted gross margin percentage is defined as adjusted gross margin divided by total revenues. We believe adjusted gross margin and adjusted gross margin percentage are useful as supplemental measures to investors of our operating profitability. Reconciliations of adjusted gross margin to gross margin are presented below.
Discretionary cash flow is considered a non-GAAP measure. Discretionary cash flow is defined as net cash provided by operating activities less (i) maintenance capital expenditures; (ii) certain changes in operating assets and liabilities; and (iii) certain other expenses; plus certain items, as applicable, such as (w) severance expenses; (x) transaction expenses; and (y) sales tax reserve. We believe discretionary cash flow is a useful liquidity and performance measure and supplemental financial measure in assessing our ability to pay cash dividends to our stockholders, make growth capital expenditures and assess our operating performance. A reconciliation of discretionary cash flow to net cash provided by operating activities is presented below.
Free cash flow is considered a non-GAAP measure. Free cash flow is defined as net cash provided by operating activities less (i) maintenance capital expenditures; (ii) certain changes in operating assets and liabilities; (iii) certain other expenses; (iv) growth capital expenditures; and (v) other capital expenditures; plus certain items, as applicable, such as (w) severance expenses; (x) transaction expenses; (y) sales tax reserve; and (z) proceeds from sale of assets. We believe free cash flow is a liquidity measure and useful supplemental financial measure in assessing our ability to pursue business opportunities and investments to grow our business and to service our debt. A reconciliation of free cash flow to net cash provided by operating activities is presented below.
Cautionary Note Regarding Forward-Looking Statements
This news release contains, and our officers and representatives may from time to time make, "forward-looking statements" within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements are neither historical facts nor assurances of future performance. Instead, they are based only on our current beliefs, expectations and assumptions regarding the future of our business, future plans and strategies, projections, anticipated events and trends, the economy and other future conditions. Forward-looking statements can be identified by words such as: "anticipate," "intend," "plan," "goal," "seek," "believe," "project," "estimate," "expect," "strategy," "future," "likely," "may," "should," "will" and similar references to future periods. Examples of forward-looking statements include, among others, statements we make regarding: (i) expected operating results, such as revenue growth and earnings, including the integration of acquired businesses and assets into our operations, and our ability to service our indebtedness; (ii) anticipated levels of capital expenditures and uses of capital; (iii) current or future volatility in the credit markets and future market conditions; (iv) potential or pending acquisition transactions or other strategic transactions, the timing thereof, the receipt of necessary approvals to close such acquisitions, our ability to finance such acquisitions, and our ability to achieve the intended operational, financial, and strategic benefits from any such transactions; (v) expectations of the effect on our financial condition of claims, litigation, environmental costs, contingent liabilities and governmental and regulatory investigations and proceedings; (vi) production and capacity forecasts for the natural gas and oil industry; (vii) strategy for customer retention, growth, fleet maintenance, market position and financial results; (viii) interest rate hedges; and (ix) strategy for risk management.
Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict and many of which are outside of our control. Our actual results and financial condition may differ materially from those indicated in the forward-looking statements. Therefore, you should not place undue reliance on any of these forward-looking statements. Please refer to the factors discussed throughout the "Risk Factors" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations" sections and elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2025, filed with the U.S. Securities and Exchange Commission, which can be found at the SEC’s website www.sec.gov. The discussion of these factors is specifically incorporated by reference into this news release.
Any forward-looking statement made by us in this news release is based only on information currently available to us and speaks only as of the date on which it is made. Except as may be required by applicable law, we undertake no obligation to publicly update any forward-looking statement whether as a result of new information, future developments or otherwise.
KODIAK GAS SERVICES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
Three Months Ended (in thousands, except per share data) March 31, 2026 December 31, 2025 March 31, 2025 Revenues: Contract Services $ 306,985 $ 301,810 $ 288,956 Other Services 38,774 31,061 40,686 Total revenues 345,759 332,871 329,642 Operating expenses: Cost of operations (exclusive of depreciation and amortization shown below): Contract Services 90,259 92,899 93,235 Other Services 32,619 27,100 35,226 Depreciation and amortization 68,681 73,192 70,529 Long-lived asset impairment — 6,344 — Selling, general and administrative 46,127 38,923 32,255 Loss on sale of assets 1,261 7,519 9,211 Total operating expenses 238,947 245,977 240,456 Income from operations 106,812 86,894 89,186 Other income (expenses): Interest expense (48,741 ) (48,985 ) (47,224 ) Loss on extinguishment of debt (36,512 ) — — Other income (expense), net (939 ) 1,072 (402 ) Total other expenses, net (86,192 ) (47,913 ) (47,626 ) Income before income taxes 20,620 38,981 41,560 Income tax expense 2,760 14,216 10,524 Net income 17,860 24,765 31,036 Less: Net income attributable to noncontrolling interests 55 140 625 Net income attributable to common shareholders $ 17,805 $ 24,625 $ 30,411 Earnings per share attributable to common shareholders: Basic $ 0.20 $ 0.28 $ 0.34 Diluted $ 0.20 $ 0.28 $ 0.33 Weighted average shares outstanding: Basic 85,942 86,184 87,879 Diluted 87,501 87,483 90,606
KODIAK GAS SERVICES, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(in thousands) March 31, 2026 December 31, 2025 Assets Current assets: Cash and cash equivalents $ 94,363 $ 3,179 Accounts receivable, net 238,376 197,600 Inventories, net 103,926 101,530 Contract assets 7,725 5,190 Prepaid expenses and other current assets 15,150 15,637 Total current assets 459,540 323,136 Property, plant and equipment, net 3,419,137 3,377,555 Operating lease right-of-use assets, net 44,361 42,218 Finance lease right-of-use assets, net 5,892 6,500 Goodwill 408,681 408,681 Identifiable intangible assets, net 149,514 154,474 Fair value of derivative instruments 6,578 4,664 Other assets 939 789 Total assets $ 4,494,642 $ 4,318,017 Liabilities and Stockholders’ Equity Current liabilities: Accounts payable $ 71,831 $ 72,974 Accrued liabilities 195,729 218,463 Contract liabilities 92,413 94,505 Total current liabilities 359,973 385,942 Long-term debt, net of unamortized debt issuance cost 2,787,003 2,555,250 Operating lease liabilities 42,122 39,391 Finance lease liabilities 3,775 4,405 Deferred tax liabilities 125,460 122,851 Other liabilities 1,303 2,782 Total liabilities $ 3,319,636 $ 3,110,621 Stockholders’ equity: Preferred stock 2 4 Common stock 908 903 Additional paid-in capital 1,326,985 1,334,333 Treasury stock, at cost (143,968 ) (143,968 ) Noncontrolling interest 3,597 4,910 Accumulated other comprehensive loss (99 ) (1,586 ) (Accumulated deficit) Retained earnings (12,419 ) 12,800 Total stockholders’ equity 1,175,006 1,207,396 Total liabilities and stockholders’ equity $ 4,494,642 $ 4,318,017
KODIAK GAS SERVICES, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31, (in thousands) 2026 2025 Cash flows from operating activities: Net income $ 17,860 $ 31,036 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 68,681 70,529 Equity compensation expense 5,890 6,978 Amortization of debt issuance costs 2,963 3,133 Non-cash lease expense 3,260 2,555 Provision for credit losses 1,169 — Inventory reserve — 123 Loss on sale of assets 1,261 9,211 Amortization of interest rate swap — 2,426 Deferred tax provision 2,709 7,016 Loss on extinguishment of debt 36,512 — Changes in operating assets and liabilities Accounts receivable (41,945 ) (23 ) Inventories (2,396 ) 3,416 Contract assets (2,535 ) (12,313 ) Prepaid expenses and other current assets 1,604 (1,235 ) Accounts payable (38 ) 2,182 Accrued and other liabilities (22,916 ) (16,258 ) Contract liabilities (2,092 ) 5,913 Other assets 1,195 (361 ) Net cash provided by operating activities 71,182 114,328 Cash flows from investing activities: Purchase of property, plant and equipment (118,370 ) (77,553 ) Proceeds from sale of assets 3,467 9,376 Net cash used for investing activities (114,903 ) (68,177 ) Cash flows from financing activities: Borrowings on debt instruments 1,353,857 347,491 Payments on debt instruments (1,147,272 ) (344,204 ) Principal payments on other borrowings (395 ) (1,950 ) Payment of debt issuance cost (12,958 ) — Principal payments on finance leases (593 ) (719 ) Dividends paid to stockholders (42,604 ) (36,445 ) Repurchase of common shares — (9,956 ) Cash paid for shares withheld to cover taxes (14,979 ) (2,827 ) Net effect on deferred taxes and taxes payable related to the vesting of restricted stock — 16 Distributions to noncontrolling interest (151 ) (357 ) Net cash provided by (used for) financing activities 134,905 (48,951 ) Net increase (decrease) in cash and cash equivalents 91,184 (2,800 ) Cash and cash equivalents - beginning of period 3,179 4,750 Cash and cash equivalents - end of period $ 94,363 $ 1,950
KODIAK GAS SERVICES, INC.
RECONCILIATION OF NET INCOME AND DILUTED EARNINGS PER SHARE
TO ADJUSTED NET INCOME AND ADJUSTED DILUTED EARNINGS PER SHARE
(UNAUDITED)
Three Months Ended (in thousands) March 31, 2026 December 31, 2025 March 31, 2025 Net income $ 17,860 $ 24,765 $ 31,036 Long-lived asset impairment — 6,344 — Loss on extinguishment of debt 36,512 — — Severance expense 72 2,121 376 Transaction expenses (1) 8,315 793 1,786 Tax effect of adjustments (2) (10,758 ) 1,238 (561 ) Adjusted net income $ 52,001 $ 35,261 $ 32,637 Weighted-average common shares outstanding: Diluted 87,501 87,483 90,606 Diluted earnings per common share $ 0.20 $ 0.28 $ 0.33 Long-lived asset impairment — 0.07 — Loss on extinguishment of debt 0.42 — — Severance expense — 0.02 0.01 Transaction expenses (1) 0.10 0.01 0.02 Tax effect of adjustments (2) (0.13 ) 0.02 (0.01 ) Adjusted diluted earnings per common share $ 0.59 $ 0.40 $ 0.35
(1) Represents certain costs associated with non-recurring professional services and other costs, primarily primarily related to the acquisition of DPS and secondary offerings. (2) Represents the estimated tax effect of adjustments calculated using the Company’s adjusted tax provision.
KODIAK GAS SERVICES, INC.
RECONCILIATION OF NET INCOME (LOSS) TO ADJUSTED EBITDA
(UNAUDITED)
Three Months Ended (in thousands, excluding percentages) March 31, 2026 December 31,
2025 March 31, 2025 Net income $ 17,860 $ 24,765 $ 31,036 Interest expense 48,741 48,985 47,224 Income tax expense 2,760 14,216 10,524 Depreciation and amortization 68,681 73,192 70,529 Long-lived asset impairment — 6,344 — Loss on extinguishment of debt 36,512 — — Equity compensation expense 5,890 6,516 6,978 Severance expense 72 2,121 376 Transaction expenses (1) 8,315 793 1,786 Loss on sale of assets 1,261 7,519 9,211 Adjusted EBITDA $ 190,092 $ 184,451 $ 177,664 Net income percentage 5.2 % 7.4 % 9.4 % Adjusted EBITDA percentage 55.0 % 55.4 % 53.9 %
(1) Represents certain costs associated with non-recurring professional services and other costs, primarily primarily related to the acquisition of DPS and secondary offerings.
KODIAK GAS SERVICES, INC.
RECONCILIATION OF ADJUSTED GROSS MARGIN TO GROSS MARGIN
(UNAUDITED)
Contract Services
Three Months Ended (in thousands, excluding percentages) March 31, 2026 December 31, 2025 March 31, 2025 Total revenues $ 306,985 $ 301,810 $ 288,956 Cost of operations (excluding depreciation and amortization) (90,259 ) (92,899 ) (93,235 ) Depreciation and amortization (68,681 ) (73,192 ) (70,529 ) Gross margin $ 148,045 $ 135,719 $ 125,192 Gross margin percentage 48.2 % 45.0 % 43.3 % Depreciation and amortization 68,681 73,192 70,529 Adjusted gross margin $ 216,726 $ 208,911 $ 195,721 Adjusted gross margin percentage 70.6 % 69.2 % 67.7 %
Other Services
Three Months Ended (in thousands, excluding percentages) March 31, 2026 December 31, 2025 March 31, 2025 Total revenues $ 38,774 $ 31,061 $ 40,686 Cost of operations (excluding depreciation and amortization) (32,619 ) (27,100 ) (35,226 ) Depreciation and amortization — — — Gross margin $ 6,155 $ 3,961 $ 5,460 Gross margin percentage 15.9 % 12.8 % 13.4 % Depreciation and amortization — — — Adjusted gross margin $ 6,155 $ 3,961 $ 5,460 Adjusted gross margin percentage 15.9 % 12.8 % 13.4 %
KODIAK GAS SERVICES, INC.
RECONCILIATION OF NET CASH PROVIDED BY OPERATING ACTIVITIES TO DISCRETIONARY CASH FLOW AND FREE CASH FLOW
(UNAUDITED)
Three Months Ended (in thousands) March 31, 2026 December 31, 2025 March 31, 2025 Net cash provided by operating activities $ 71,182 $ 194,862 $ 114,328 Maintenance capital expenditures (17,758 ) (22,265 ) (16,407 ) Severance expense 72 2,121 376 Transaction expenses (1) 8,315 793 1,786 Change in operating assets and liabilities 69,123 (60,613 ) 18,679 Other (2) (4,429 ) (2,374 ) (2,678 ) Discretionary cash flow $ 126,505 $ 112,524 $ 116,084 Growth capital expenditures (3)(4)(5) (85,552 ) (25,253 ) (55,983 ) Other capital expenditures (4) (7,458 ) (11,895 ) (22,258 ) Proceeds from sale of assets 3,467 3,233 9,376 Free cash flow $ 36,962 $ 78,609 $ 47,219
(1) Represents certain costs associated with non-recurring professional services and other costs, primarily related to the acquisition of DPS and secondary offerings. (2) Includes non-cash lease expense, provision for credit losses and inventory reserve. (3) Growth capital expenditures includes an $18.0 million investment in power generation infrastructure to support our recently acquired power distribution business for the three months ended March 31, 2026. (4) For the three months ended March 31, 2026, December 31, 2025, and March 31, 2025, growth and other capital expenditures includes a $6.5 million decrease, a $6.5 million increase and a $14.1 million increase in accrued capital expenditures, respectively. (5) For the three months ended March 31, 2026, December 31, 2025, and March 31, 2025, growth capital expenditures includes a $1.0 million increase, a $0.7 million increase and a $1.2 million increase, in a non-cash sales tax accrual on compression equipment purchases, respectively.
View source version on businesswire.com: https://www.businesswire.com/news/home/20260511291625/en/
Contacts
Investor Contact Graham Sones, VP – Investor Relations
ir@kodiakgas.com
(936) 755-3529
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- Why is Enliven Therapeutics (ELVN) One of the Best Performing Healthcare Stocks so Far in 2026?
May 10, 2026
Enliven Therapeutics, Inc. (NASDAQ:ELVN) is one of the best performing healthcare stocks so far in 2026. On April 30, Mizuho reaffirmed an Outperform rating on Enliven Therapeutics, Inc. (NASDAQ:ELVN), setting a price target of $45. The rating update came after Merck noted during its fiscal Q1 earnings call that it believes Terns’ TERN-701 major molecular response “will be north of 50% and within the confidence interval as had been publicly stated.” The firm believes the comments to be a positive for ELVN-001, adding that today’s “high-level quantification” only further supports the significant degradation.
Enliven Therapeutics, Inc. (NASDAQ:ELVN) also received a rating update from Clear Street on April 27. The firm lifted the price target on the stock to $55 from $36, maintaining a Buy rating on the shares. The firm stated that it left meetings with management with increased conviction in ELVN-001 as a differentiated ATP-site binder for BCR-ABL1. For additional reference, Enliven Therapeutics, Inc. (NASDAQ:ELVN) reported in fiscal Q4 and full year 2025 earnings that it has a strong balance with $463 million in cash, cash equivalents, and marketable securities, which is anticipated to provide cash runway into the first half of 2029.
Enliven Therapeutics, Inc. (NASDAQ:ELVN) is a clinical-stage biopharmaceutical company with a focus on the discovery and development of small-molecule therapeutics. The company’s pipeline includes BCR-ABL Program: ELVN-001and HER2 Program: ELVN-002.
While we acknowledge the potential of ELVN as an investment, we believe certain AI stocks offer greater upside potential and carry less downside risk. If you're looking for an extremely undervalued AI stock that also stands to benefit significantly from Trump-era tariffs and the onshoring trend, see our free report on the best short-term AI stock.
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- Alpha (AMR) Q1 2026 Earnings Call Transcript
May 8, 2026
Image source: The Motley Fool.
DATE
Friday, May 8, 2026 at 10:00 a.m. ET
CALL PARTICIPANTS
Chief Executive Officer — Andy Eidson Chief Financial Officer — J. Todd Munsey President — Daniel E. Horn Chief Operating Officer — Jason E. Whitehead
Need a quote from a Motley Fool analyst? Email pr@fool.com
Full Conference Call Transcript
Andy Eidson: Given this and since we expect improved operational performance in both coal volumes and cost of coal sales for the balance of 2026, we believe it is still possible to finish the year within the top end of our existing cost guidance range of $95 to $101 per ton. However, if the Iranian conflict and its resulting inflationary impacts persist, we will likely adjust our cost guidance upward. Our realizations improved quarter over quarter largely due to increases in the low-vol indexes that occurred in recent months due to supply-related issues from flooding in Australia. However, there are historically unusual divergences within the indexes that have either persisted or gotten more pronounced in recent weeks.
Within low-vol pricing, the Australian PLV is currently $45 per metric ton higher, or 23% more, than the U.S. East Coast Low Vol Index. And of particular importance to us and our portfolio, there is a further $36 per ton gap down from the U.S. East Coast Low Vol to the U.S. East Coast High Vol A, another difference of 23%. The U.S. East Coast spread from Low Vol to High Vol A is likely related to how oversupplied the market for high vol has become with additional tons recently brought to market in an already weak environment.
We continually evaluate the productive capacity of our portfolio alongside the needs of the market, both in the near future and from a longer-term perspective. We are watching to see if either of those index spreads tie into a more normalized level or if the divergence persists. Across the organization, our employees are working hard to maintain safe, efficient operations despite the external headwinds we are facing. Within the first quarter, many Alpha Metallurgical Resources, Inc. teams received third-party recognition for exceptional work in the areas of operational safety, mine rescue, environmental stewardship, and reclamation. I commend each of our team members who make positive contributions through their work every day.
Our sales team also tackled a difficult challenge by successfully planning for and mitigating the potential disruption of a four-week outage in March at Dominion Terminal. They diligently worked to keep as much Alpha Metallurgical Resources, Inc. coal moving as possible both before and after the downtime, while strategically utilizing our Hampton Roads terminal capacity beyond DTA. We are grateful to all of our partners for helping us overcome these challenges, and we are especially appreciative of the DTA team for their work to do so many equipment maintenance tasks and upgrades in such a short time. With that, I will turn the call over to Todd for a review of our first quarter financial results.
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J. Todd Munsey: Thanks, Andy. Adjusted EBITDA for the first quarter was $30 million, up from $28.5 million in 2025. We sold 3.6 million tons in Q1, down from 3.8 million tons. Met segment realizations increased quarter over quarter with an average realization of $124.39 in the first quarter, up from $115.31 in Q4. Export met tons priced against Atlantic indices and other pricing mechanisms in the first quarter realized $110.32 per ton, while export coal priced on Australian indices realized $144.09 per ton. These results are compared to realizations of $106.01 per ton and $114.96 per ton, respectively, in the fourth quarter.
Realization for our metallurgical sales in the first quarter was a total weighted average of $128.40 per ton, up from $118.10 per ton in Q4. Realizations in the incidental thermal portion of the met segment decreased to $69.41 per ton in the first quarter, down from $77.80 per ton in Q4. Cost of coal sales for our met segment increased to $107.98 per ton in Q1, up from $101.43 per ton in the fourth quarter. Alongside lower productive volumes for the quarter, higher diesel and other supply and repair costs were the primary drivers of the quarter-over-quarter cost increase.
For the first quarter, SG&A, excluding noncash stock compensation and nonrecurring items, increased to $13.5 million as compared to $10.9 million in the fourth quarter. Moving to the balance sheet and cash flows. As of March 31, 2026, Alpha Metallurgical Resources, Inc. had $317.2 million in unrestricted cash and $49.6 million in short-term investments as compared to $366.0 million of unrestricted cash and $49.6 million in short-term investments as of December 31, 2025. There was $184.3 million in unused availability under our ABL at the end of the first quarter, partially offset by a minimum required liquidity of $75 million. As of March, Alpha Metallurgical Resources, Inc. had total liquidity of $476.2 million, down from $524.3 million at December.
CapEx for the first quarter was $40.7 million, up from $29.0 million in Q4. Cash provided by operating activities was $29.0 million in the first quarter, up from $19.0 million in the fourth quarter. As of March 31, our ABL facility had no borrowings and $40.7 million of letters of credit outstanding. In terms of our committed position for 2026, at the midpoint of guidance, 48% of our metallurgical tonnage in the met segment is committed and priced at an average price of $132.03 per ton. Another 43% of our met tonnage for the year is committed but not yet priced.
The thermal byproduct portion of the met segment is fully committed and priced at the midpoint of guidance at an average price of $74.53 per ton. From a market perspective, geopolitical and weather-related supply issues influenced metallurgical coal markets in 2026, with the war in Iran causing increased volatility in the energy sector. While not directly linked to war-related electricity generation and power concerns, metallurgical coal markets also moved during the quarter with modest increases across the met coal quality spectrum. Of the four indices Alpha Metallurgical Resources, Inc. closely monitors, the Australian Premium Low Vol Index represents the largest quarterly increase of 8.6%.
The Aussie PLV index increased from $218 per metric ton on January 2 to $236.80 per metric ton on March 31, 2026. The U.S. East Coast Low Vol Index rose from $185 per metric ton in early January to $195 per metric ton by March. The U.S. East Coast High Vol A index increased from $150.5 per metric ton at the beginning of the quarter to $159.5 per metric ton at the quarter's close. And the U.S. East Coast High Vol B index increased from $144.2 per metric ton to $149.5 per metric ton at the end of the quarter.
Since then, the Australian PLV index has increased to $239.8 per metric ton as of May 7, 2026, while the U.S. East Coast Low Vol is at $195 per ton, exactly the same as at quarter end. U.S. East Coast High Vol A and High Vol B indices are also largely unchanged from quarter close at $159 and $149 per ton, respectively, as of May 7, 2026. In the seaborne thermal market, the API2 index was $95.5 per metric ton in January and increased to $125.75 per metric ton in March. Since then, the API2 index has dropped to $111.5 per metric ton as of May 7, 2026.
With that, operator, we are now ready to open the call for questions.
Operator: We will now open the call for questions. At this time, we will be conducting a question and answer session. Our first question comes from Nick Giles with B. Riley. Your line is now live.
Nick Giles: Yes. Thank you, operator. Good morning, everyone. Obviously, some higher costs in Q1 and some of it, or a lot of it, outside of your control. I was just hoping to get some more color on just kind of cost cadence starting here in Q2, just with diesel prices remaining elevated here and now. How much of that cost pressure kind of carries over into Q2? And what should we really be roughly penciling in for the quarter? Thanks. And maybe on the other side, realizations moved up. It is nice to see. Just was curious on are there any opportunities to shift more tons to kind of an Aussie-linked basis?
What kind of incremental opportunities are you seeing in South Asia, maybe as Australian supply, especially for higher-quality met, remains tight? Thanks. And maybe a last one for me is just what are you seeing in Central App in terms of some of your competitors out there? Are you seeing any production that could come back? Just an update more broadly on kind of the surrounding production areas would be helpful.
Andy Eidson: Hey, Nick. I do not want to guide too early because we are only partway through the quarter. I think diesel contributed a couple of dollars a ton of the cost pressure. Of course, that was just really a late February–March impact. So it will look like we will see a full quarter's impact of it, so you could see a little bit more than that. And also, that is the direct diesel cost.
The piece that you do not see that is buried is diesel impacts delivery cost of pretty much everything that we buy, and so you are going to see the indirect portion of that coming through supplies and maintenance, which we have also seen a step up there as well. We do expect, just from increased productive activity during the quarter compared to the first quarter, we should see some of that cost getting spread over more tons, particularly our fixed cost spread. So I do expect it to be coming down from Q1, but it is a little bit too early to tell the quantum on that.
Daniel E. Horn: Hey, Nick. This is Dan. On your question about shifting to Aussie-linked pricing and opportunities in Asia, I think the short answer is yes to the extent that we have some medium-vol and low-vol coals that we can place into the Asian markets. The landscape for high vol coals into Asia is pretty tough right now. You are essentially matching the lowest price the competitor throws out that day. So even if it is linked to the Aussie index, it is discounted pretty heavily. We are pretty selective on which opportunities we pursue. It is not so much about the indexes; it is about the ultimate price and the netback to our coal mines.
But I think there is some upside as demand increases, and if the Aussie production for the higher-quality coals remains a little bit short, there are opportunities.
Andy Eidson: Yeah. Nick, I will take your Central App question first, and I will ask Dan to jump in if he has anything additional. We obviously have seen some tons coming offline really earlier in Q1, but as the quarter has gone on, it has been some smaller incremental batches. I do not think it is anything that is terribly needle moving thus far. I think the quantum has been less than what is required to fill some of the gaps in the supply and demand situation. Dan, any thoughts on that?
Daniel E. Horn: No, I think you said it well, Andy. I mean, you look at today versus where we were a couple of years ago, there is probably something like 11 million tons of new longwall high vol production that is in the marketplace, and the round numbers of how many tons have come out of Central App is probably 1 million to 2 million, somewhere in that range. So still a pretty good imbalance. Global demand for the use of high vol coals is something less than it was a couple of years ago too. So as demand improves, that will help somewhat with the rebalancing.
Nick Giles: Got it. Understood. Okay. Well, thanks, guys, and best of luck.
Operator: Our next question comes from Nathan Martin with The Benchmark Company. Please proceed with your question.
Nathan Martin: Thanks, operator. Good morning, everyone. I think it would be helpful to get some thoughts on shipping cadence for the balance of the year. I think, Andy, you said you expect Q2 to improve for the reasons we already talked about. Does that get made up mainly in Q2, or do you kind of expect those tons to be spread out in subsequent quarters? And then maybe, Dan, obviously freight rates elevated post the start of the conflict in the Middle East. I believe you guys have traditionally sold very little based on CFR prices. Is that still true? And then, the spot market maybe a little bit quiet—you just mentioned High Vol especially.
What do you think needs to happen for things to pick up there?
Andy Eidson: Hey, Nate. I would expect—because normally we have a bit of a bell curve during a regular year where Q1 and Q4 are going to be your lightest quarters, and Q2 and Q3 through the summer have your best shipments—I think it will probably look similar to that this year. I do think most of the makeup, where it happens, will happen in the middle two quarters. And then we will probably start tailing off a little bit as we get to the end of the year with the holidays and that kind of stuff. So it is going to look like a normal year; it is just a little bit steeper curve from Q1 into Q3.
Daniel E. Horn: Yes, on the freight, you are correct. Most of our business is FOB vessel. To the extent we do some chartering, we have seen freight increase—pick a number—around a 40% increase in the freight rates. To the extent that coal travels halfway around the world to South Asia and places like that, that is a pretty significant hit. And the impact of that is some of that freight will be shared between the buyer and the seller. It is not necessarily all passed over, particularly on new business. If you are chasing new spot business, freight is absolutely a factor, as opposed to a term contract where you have a set price.
In that instance, the freight responsibility shifts to the buyer. As to what has to happen for the spot market to pick up, like I mentioned to Nick, I think we have to see some demand improvement and some continued supply discipline. We are more oversupplied than we have seen in a while. We have seen it before in the marketplace, but at this moment in time, it is a pretty significant hill to climb for most of the U.S. producers here.
Nathan Martin: And then maybe the 3.1 million tons of export met that you guys have committed and priced—can you give us an idea of that mix by quality? And could we get an update on Kingston Wildcat? Maybe from Jason? It seems like those tons coming online may be opportune timing given the wide relativities we are seeing between premium low vol and high vol.
Daniel E. Horn: It is primarily high vols and mid vols with a little low vol thrown in there. We do not give an exact breakdown. I will point out, and kind of to your question on the ship cadence too, as the Wildcat mine—our low-vol mine—ramps during the year, that mix will include, we expect, more low vol going into that mix. I cannot quantify it any more than that, but our long-term strategy was to put more of the high-rank, higher-quality coke strength coals into our portfolio. That should continue this year and next.
Jason E. Whitehead: Sure. Good morning. The Wildcat mine is on coal and there are tons coming out of the mine. They are still in the development phases, but we actually plan for that to conclude here in Q2, and in Q3 and Q4 we actually see a ramp of production coming out of the mine.
Operator: Our next question comes from Matthew Key with Texas Capital Securities. Please proceed with your question.
Matthew Key: Good morning, everyone, and thanks for taking my questions. Kind of piggybacking off of the diesel discussions, I was wondering if you could provide a sensitivity to diesel pricing that we could use as a general rule of thumb moving forward? And is there anything that the company could do to manage some of these inflationary cost pressures? Do you currently do any diesel hedging, and would that be something you would consider in the future?
Andy Eidson: That is a tough one, Matt, as far as knowing that off the top of my head. I am looking at Todd right now to see if he has some viewpoints on that.
J. Todd Munsey: Yes, Matt. In a typical year, we use about 22 million to 23 million gallons of diesel. If you think about the balance of the year, with the movement we have had in diesel prices—and to the point Andy made earlier—the diesel we use, we expect that to be a couple of bucks influence on the cost. But then there are also the surcharges and whatnot that will flow through from transportation-related costs. Hopefully that helps a little bit as you think about the balance of the year. Obviously, we all hope that issue goes away, but if not, that is kind of how we think about it.
Andy Eidson: Yes. Historically, we have done some, not necessarily diesel hedging, but buying forwards through our diesel providers to lock in pricing around budget time. We have done that some of the past three to four years. Most of the time, it has actually gone upside down on us. This year, of course, happens to be the one where we chose not to do those forwards because back in August and September, who could have seen this coming.
But it is something that we are discussing actively simply because the world seems to be getting more and more politically volatile, to a degree where it may require locking in as many of your inputs as possible whenever you have the opportunity, just because things do seem to be changing at a pace that is faster than the world can actually keep up with.
Matthew Key: Got it. That is super helpful. I will stop there. Appreciate the time, and best of luck.
Operator: Our next question comes from Analyst with Jefferies. Please proceed with your question.
Analyst: Hey, guys. Thanks. It is Chris Lafemina from Jefferies here. Just wanted to go back to the market. We are all kind of waiting for the high vol discounts to narrow, and this has been an issue for quite a long time. Now we have iron ore prices rising, energy prices globally rising, premium low-vol met coal prices strengthening pretty materially, global steel markets appear to be okay, but the high vol discount is widening. I am wondering if something else is going on.
I understand the point about there being quite a bit of high vol supply that has come online, but I would have thought, if anything, that would have brought the premium low vol price down rather than just result in a wider spread. So is there anything else going on in that market that is more structurally problematic, or is this purely a short-term cyclical issue that we should expect to resolve? And if it is a cyclical issue, why has it not resolved yet? It has been going on for quite an extended period of time, and the spreads have been wider than we have ever seen and do not seem to be reversing at all.
Just trying to figure out what is going on there. Thanks.
Daniel E. Horn: Chris, this is Dan. I will try to unpack that a little bit. The PLV is its own creature. It is an index that follows primarily Australian coals. We use it; we link our higher-quality low vols and medium vols to that index. We do believe that the U.S. East Coast Low Vol Index is too far below the Aussie index. When there is a shortage of Australian PLV, we get phone calls and we—U.S. producers that produce low vol—ship our coal to replace that PLV. So we believe that the gap between East Coast Low Vol and PLV is too wide, to your point. The high vol coals are used differently.
They do not contribute to the coke strength; they are used for plastic properties and, arguably at times, just as a cheap filler. They move differently, but they have been depressed, and again, I think that is more of just old-fashioned supply and demand working on that. Buyers are trying—when they see the potential for low price or big discounts, they will adjust their blends to try to buy more of that. I think they will run into the ocean freight issue—that those tons of coal that have to go halfway around the world at a high freight number are not going to travel well if they are low-value coals.
I would not lump all that together the way you did; I think you have to break that apart.
Andy Eidson: And, Chris, this is Andy. If I could add one more piece to that. The differential between East Coast High Vol A and East Coast Low Vol is somewhat of a recent phenomenon. If you go back to the first of 2025, that differential was only $5. Now it has climbed to $38. And so I do think that is pretty directly attributable to all the new tonnage that has come online, both in Northern Appalachia and in Alabama, just hitting a market that is having trouble absorbing it.
Analyst: Understood. Thanks a lot for that. Appreciate it. Good luck.
Operator: We have a follow-up question from Nick Giles with B. Riley. Please proceed with your question.
Nick Giles: Yes, thanks for taking my follow-up. Just wanted to ask more broadly—we had the Presidential Memorandum Section 303 a few weeks back in April, and I wanted to ask if this has really translated to your business or if you could expect to see any benefit or funding from these actions by the administration. I think maybe some of this is more related to the thermal side; they call out baseload power generation explicitly, but even export terminals are mentioned. So could DTA, for instance, be a candidate for some sort of government support? Thanks.
Andy Eidson: Yeah, that one is still developing, as with most of these executive orders and other proclamations going back into last fall. A lot of the details are still developing real time. We are involved to a high degree with the federal government on evaluating the different programs and seeing what is out there. From what we have seen thus far, it does seem that it is mostly thermal-focused. There are some smaller areas where there may be some benefit, but as of yet, I do not think we are seeing anything that is hugely material to what we are doing right now.
Fingers crossed that some of it translates to bigger benefit on the met side of the house, but I am not sure we have seen anything in that regard yet.
Operator: We have reached the end of the question and answer session. I would now turn the call over to Andy Eidson for closing remarks.
Andy Eidson: Yes. We appreciate everyone joining us this morning for the earnings call, and we hope everyone has a great weekend. Thank you.
Operator: This concludes today's conference. You may disconnect your lines at this time, and we thank you for your participation.
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Alpha (AMR) Q1 2026 Earnings Call Transcript was originally published by The Motley Fool
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- Multiple Headwinds Weighed on N-able’s (NABL) Performance
May 8, 2026
Conestoga Capital Advisors, an asset management company, released its first-quarter 2026 investor letter. A copy of the letter can be downloaded here. The first quarter of 2026 started with optimism about the domestic economy and attractive small-cap valuations, but was marked by volatility amid geopolitical unrest in the Middle East and shifting expectations for interest rates. This unrest drove up energy prices and created a cautious global market. Energy, Basic Materials, and Industrials performed well, while software companies faced challenges due to AI disruption concerns. Market sensitivity to geopolitical events, energy prices, and inflation remains high. The first quarter saw high volatility in the Russell Microcap Growth Index, which rose over +11% by late January, then fell -18% to a -4.25% quarter-end loss, compared to -7.14% for the Conestoga Micro Cap Composite. Initial positive relative performance declined as the war in the Middle East escalated, leading investors to unwind popular momentum trades and to cover significant short positions in biotechnology. In addition, please check the Strategy’s top five holdings to know its best picks in 2026.
In its first-quarter 2026 investor letter, Conestoga Capital Advisors highlighted stocks like N-able, Inc. (NYSE:NABL). N-able, Inc. (NYSE:NABL) is a technology company offering unified endpoint management, security operations, and data protection solutions for managed service providers. On May 7, 2026, N-able, Inc. (NYSE:NABL) closed at $5.15 per share. One-month return of N-able, Inc. (NYSE:NABL) was 22.33%, and its shares lost 31.52% over the past 52 weeks. N-able, Inc. (NYSE:NABL) has a market capitalization of $970.15 million.
Conestoga Capital Advisors stated the following regarding N-able, Inc. (NYSE:NABL) in its Q1 2026 investor letter:
"N-able, Inc. (NYSE:NABL) provides cloud-based software solutions for managed service providers (MSPs), enabling them to support the IT and security needs of small and medium sized businesses. The company delivered solid 2025 results; however, its 2026 constant currency ARR growth guidance of 8–9% was perceived as modest relative to the accelerating growth seen in the hardware and semiconductor segments of the AI rally. Additionally, increased planned investments in "agentic AI" capabilities for their platform weighed on near-term margin expansion expectations, causing the stock to trail more speculative peers during the benchmark's January breakout."Is Abacus Global Management, Inc. (ABL) The Small Cap Stock with Huge Upside Potential?
N-able, Inc. (NYSE:NABL) is not on our list of 40 Most Popular Stocks Among Hedge Funds Heading Into 2026. According to our database, 28 hedge fund portfolios held N-able, Inc. (NYSE:NABL) at the end of the fourth quarter, up from 23 in the previous quarter. While we acknowledge the potential of N-able, Inc. (NYSE:NABL) as an investment, we believe certain AI stocks offer greater upside potential and carry less downside risk. If you're looking for an extremely undervalued AI stock that also stands to benefit significantly from Trump-era tariffs and the onshoring trend, see our free report on the best short-term AI stock.
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- Alpha Releases First Quarter 2026 Financial Results
May 8, 2026
Reports first quarter net loss of $11.0 million Posts Adjusted EBITDA of $30.0 million for the quarter
BRISTOL, Tenn., May 8, 2026 /PRNewswire/ -- Alpha Metallurgical Resources, Inc. (NYSE: AMR), a leading U.S. supplier of metallurgical products for the steel industry, today reported financial results for the first quarter ending March 31, 2026.(PRNewsfoto/Alpha Metallurgical Resources, Inc.)
(millions, except per share) Three months ended Mar. 31, 2026 Dec. 31, 2025 Mar. 31, 2025 Net loss ($11.0) ($17.3) ($33.9) Net loss per diluted share ($0.86) ($1.34) ($2.60) Adjusted EBITDA(1) $30.0 $28.5 $5.7 Operating cash flow $29.0 $19.0 $22.2 Capital expenditures ($40.7) ($29.0) ($38.5) Tons of coal sold 3.6 3.8 3.8
__________________________________ 1. This is a non-GAAP financial measure. A reconciliation of Net Loss to Adjusted EBITDA is included in tables accompanying the financial schedules.
"Our results for the first quarter 2026 were driven by lower volumes and higher costs," said Andy Eidson, Alpha's chief executive officer. "While we anticipated a slower shipping quarter in connection with planned outages at Dominion Terminal Associates, we experienced a greater-than-expected impact on costs in Q1 as a result of war-related increases to diesel and other supply prices, which we hope will be temporary. Therefore, we are maintaining our cost of coal sales guidance range for the year with the expectation of better cost performance in subsequent quarters. If the Iran conflict persists throughout the year, we expect the resulting impact on diesel and supply costs would require us to revise our cost of coal sales guidance range upward."
Financial Performance
Alpha reported a net loss of $11.0 million, or $0.86 per diluted share, for the first quarter 2026, as compared to net loss of $17.3 million, or $1.34 per diluted share, in the fourth quarter 2025.
Total Adjusted EBITDA was $30 million for the first quarter, compared to $28.5 million in the fourth quarter 2025.
Coal Revenues
(millions) Three months ended Mar. 31, 2026 Dec. 31, 2025 Met segment $523.5 $519.1 Met segment (excl. freight & handling)(1) $447.3 $436.3 Tons Sold (millions) Three months ended Mar. 31, 2026 Dec. 31, 2025 Met segment 3.6 3.8
__________________________________ 1. Represents Non-GAAP coal revenues which is defined and reconciled under "Non-GAAP Financial Measures" and "Results of Operations."
Coal Sales Realization(1)
(per ton) Three months ended Mar. 31, 2026 Dec. 31, 2025 Met segment $124.39 $115.31
__________________________________ 1. Represents Non-GAAP coal sales realization which is defined and reconciled under "Non-GAAP Financial Measures" and "Results of Operations."
First quarter net realized pricing for the Met segment was $124.39 per ton.
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The table below provides a breakdown of our Met segment coal sold in the first quarter by pricing mechanism.
(in millions, except per ton data) Met Segment Sales Three months ended Mar. 31, 2026 Tons Sold Coal Revenues Realization/ton(1) % of Met Tons
Sold Domestic 0.8 $111.1 $137.27 24 % Export - Australian indexed 1.1 $162.3 $144.95 33 % Export - other pricing mechanisms 1.4 $157.0 $110.32 43 % Total Met coal revenues 3.4 $430.4 $128.40 100 % Thermal coal revenues 0.2 $16.9 $69.41 Total Met segment coal revenues
(excl. freight & handling)(1) 3.6 $447.3 $124.39
__________________________________ 1. Represents Non-GAAP coal sales realization which is defined and reconciled under "Non-GAAP Financial Measures" and "Results of Operations."
Cost of Coal Sales
(in millions, except per ton data) Three months ended Mar. 31, 2026 Dec. 31, 2025 Met segment $474.4 $478.5 Met segment (excl. freight & handling/idle)(1) $388.3 $383.8 (per ton) Met segment(1) $107.98 $101.43
__________________________________ 1. Represents Non-GAAP cost of coal sales and Non-GAAP cost of coal sales per ton which is defined and reconciled under "Non-GAAP Financial Measures" and "Results of Operations."
Alpha's Met segment cost of coal sales increased to an average of $107.98 per ton in the first quarter, compared to $101.43 per ton in the fourth quarter 2025. Higher diesel and other supply costs were the primary contributors to the increase in costs.
Liquidity and Capital Resources
Cash provided by operating activities in the first quarter increased to $29.0 million as compared to $19.0 million in the fourth quarter 2025. Capital expenditures for the first quarter were $40.7 million compared to $29.0 million for the fourth quarter 2025.
As of March 31, 2026, the company had total liquidity of $476.2 million, including cash and cash equivalents of $317.2 million, short-term investments of $49.6 million, and $184.3 million of unused availability under the asset-based revolving credit facility (ABL), partially offset by a minimum required liquidity of $75.0 million as required by the ABL. As of March 31, 2026, the company had no borrowings and $40.7 million in letters of credit outstanding under the ABL. Total long-term debt, including the current portion of long-term debt as of March 31, 2026, was $12.2 million.
Share Repurchase Program
As previously announced, Alpha's board of directors authorized a share repurchase program allowing for the expenditure of up to $1.5 billion for the repurchase of the company's common stock. As of April 30, 2026, the company had acquired approximately 7.0 million shares of common stock at a cost of approximately $1.2 billion, or approximately $166.18 per share. The number of common stock shares outstanding as of April 30, 2026 was 12,714,624, not including the potential effect of unvested equity awards.
The timing and amount of share repurchases will be based on various factors, including but not limited to market conditions, the trading price of the stock, applicable legal requirements, compliance with the provisions of the company's debt agreements, and other factors.
Results of Alpha's 2026 Annual Meeting of Stockholders
The company's annual meeting of stockholders was held on May 6, 2026, and stockholders re-elected all six members of Alpha's board of directors to additional one-year terms and approved all other items proposed by the board for consideration at the meeting. The complete voting results from the annual meeting have been filed with the Securities and Exchange Commission on Form 8-K.
2026 Operational Performance Update
As of April 29, 2026, Alpha has committed and priced approximately 48% of its metallurgical coal for 2026 at an average price of $132.37 per ton. At the midpoint of guidance, Alpha's thermal coal is fully committed for the year at an average price of $74.53 per ton.
2026 Guidance in millions of tons Low High Metallurgical 14.4 15.4 Thermal 0.7 1.1 Met segment - total shipments 15.1 16.5 Committed/Priced1,2,3 Committed Volume (in millions of
tons) Average Price Metallurgical - domestic 4.1 $136.38 Metallurgical - export 3.1 $127.02 Metallurgical total 48 % 7.2 $132.37 Thermal 100 % 1.2 $74.53 Met segment 53 % 8.4 $124.37 Committed/Unpriced1,3 Committed Metallurgical total 43 % Thermal — % Met segment 40 % Costs per ton4 Low High Met segment $95.00 $101.00 In millions (except taxes) Low High SG&A5 $53 $59 Idle operations expense $24 $32 Net cash interest income $2 $6 DD&A $160 $174 Capital expenditures $148 $168 Capital contributions to equity affiliates6 $35 $45 Cash tax rate 0 % 5 %
Notes: 1. Based on committed and priced coal shipments as of April 29, 2026. Committed percentage based on the midpoint of shipment guidance range. 2. Actual average per-ton realizations on committed and priced tons recognized in future periods may vary based on actual freight expense in future periods relative to assumed freight expense embedded in projected average per-ton realizations. 3. Includes estimates of future coal shipments based upon contract terms and anticipated delivery schedules. Actual coal shipments may vary from these estimates. 4. Note: The Company is unable to present a quantitative reconciliation of its forward-looking non-GAAP cost of coal sales per ton sold financial measures to the most directly comparable GAAP measures without unreasonable efforts due to the inherent difficulty in forecasting and quantifying with reasonable accuracy significant items required for the reconciliation. The most directly comparable GAAP measure, GAAP cost of sales, is not accessible without unreasonable efforts on a forward-looking basis. The reconciling items include freight and handling costs, which are a component of GAAP cost of sales. Management is unable to predict without unreasonable efforts freight and handling costs due to uncertainty as to the end market and FOB point for uncommitted sales volumes and the final shipping point for export shipments. These amounts have varied historically and may continue to vary significantly from quarter to quarter and material changes to these items could have a significant effect on our future GAAP results. 5. Excludes expenses related to non-cash stock compensation and non-recurring expenses. 6. Includes contributions to fund normal operations at our DTA export facility and expected capital investments related to the facility upgrades.
Conference Call
The company plans to hold a conference call regarding its first quarter results on May 8, 2026, at 10:00 a.m. Eastern time. The conference call will be available live on the investor section of the company's website at https://alphametresources.com/investors. Analysts who would like to participate in the conference call should dial 877-407-0832 (domestic toll-free) or 201-689-8433 (international) approximately 15 minutes prior to start time.
About Alpha Metallurgical Resources
Alpha Metallurgical Resources (NYSE: AMR) is a Tennessee-based mining company with operations across Virginia and West Virginia. With customers across the globe, high-quality reserves and significant port capacity, Alpha reliably supplies metallurgical products to the steel industry. For more information, visit www.AlphaMetResources.com.
Forward-Looking Statements
This news release includes forward-looking statements. These forward-looking statements are based on Alpha's expectations and beliefs concerning future events and involve risks and uncertainties that may cause actual results to differ materially from current expectations. These factors are difficult to predict accurately and may be beyond Alpha's control. Forward-looking statements in this news release or elsewhere speak only as of the date made. New uncertainties and risks arise from time to time, and it is impossible for Alpha to predict these events or how they may affect Alpha. Except as required by law, Alpha has no duty to, and does not intend to, update or revise the forward-looking statements in this news release or elsewhere after the date this release is issued. In light of these risks and uncertainties, investors should keep in mind that results, events or developments discussed in any forward-looking statement made in this news release may not occur. See Alpha's filings with the U.S. Securities and Exchange Commission for more information.
FINANCIAL TABLES FOLLOW
Non-GAAP Financial Measures
The discussion below contains "non-GAAP financial measures." These are financial measures that either exclude or include amounts that are not excluded or included in the most directly comparable measures calculated and presented in accordance with generally accepted accounting principles in the United States ("U.S. GAAP" or "GAAP"). Specifically, we make use of the non-GAAP financial measures "Adjusted EBITDA," "non-GAAP coal revenues," "non-GAAP coal sales realization per ton," "non-GAAP cost of coal sales," "non-GAAP cost of coal sales per ton," "non-GAAP coal margin," and "non-GAAP coal margin per ton." In addition to net income (loss), we use Adjusted EBITDA to measure the operating performance of our reportable segment. Adjusted EBITDA does not purport to be an alternative to net income (loss) as a measure of operating performance or any other measure of operating results, financial performance, or liquidity presented in accordance with GAAP. Moreover, this measure is not calculated identically by all companies and therefore may not be comparable to similarly titled measures used by other companies. Adjusted EBITDA is presented because management believes it is a useful indicator of the financial performance of our coal operations. We use non-GAAP coal revenues to present coal revenues generated, excluding freight and handling fulfillment revenues. Non-GAAP coal sales realization per ton is calculated as non-GAAP coal revenues divided by tons sold. We use non-GAAP cost of coal sales to adjust cost of coal sales to remove freight and handling costs, depreciation, depletion and amortization - production (excluding the depreciation, depletion and amortization related to selling, general and administrative functions), accretion on asset retirement obligations, amortization of acquired intangibles, and idled and closed mine costs. Non-GAAP cost of coal sales per ton is calculated as non-GAAP cost of coal sales divided by tons sold. Non-GAAP coal margin is calculated as non-GAAP coal revenues less non-GAAP cost of coal sales. Non-GAAP coal margin per ton is calculated as non-GAAP coal margin divided by tons sold. The presentation of these measures should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP.
Management uses non-GAAP financial measures to supplement GAAP results to provide a more complete understanding of the factors and trends affecting the business than GAAP results alone. The definition of these non-GAAP measures may be changed periodically by management to adjust for significant items important to an understanding of operating trends and to adjust for items that may not reflect the trend of future results by excluding transactions that are not indicative of our core operating performance. Furthermore, analogous measures are used by industry analysts to evaluate our operating performance. Because not all companies use identical calculations, the presentations of these measures may not be comparable to other similarly titled measures of other companies and can differ significantly from company to company depending on long-term strategic decisions regarding capital structure, the tax jurisdictions in which companies operate, capital investments and other factors.
Included below are reconciliations of non-GAAP financial measures to GAAP financial measures.
ALPHA METALLURGICAL RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (Amounts in thousands, except share and per share data) Three Months Ended March 31, 2026 2025 Revenues: Coal revenues $ 523,533 $ 529,667 Other revenues 1,454 2,290 Total revenues 524,987 531,957 Costs and expenses: Cost of coal sales (exclusive of items shown separately below) 474,389 504,584 Depreciation, depletion and amortization 39,926 43,910 Accretion on asset retirement obligations 5,215 5,614 Amortization of acquired intangibles 876 1,357 Selling, general and administrative expenses (exclusive of
depreciation, depletion and amortization shown separately above) 16,598 15,424 Other operating (income) loss (1,585) 1,243 Total costs and expenses 535,419 572,132 Loss from operations (10,432) (40,175) Other (expense) income: Interest expense (841) (763) Interest income 4,206 4,046 Equity loss in affiliates (5,733) (4,960) Miscellaneous expense, net (3,558) (3,532) Total other expense, net (5,926) (5,209) Loss before income taxes (16,358) (45,384) Income tax benefit 5,326 11,437 Net loss $ (11,032) $ (33,947) Basic loss per common share $ (0.86) $ (2.60) Diluted loss per common share $ (0.86) $ (2.60) Weighted average shares – basic 12,800,037 13,047,607 Weighted average shares – diluted 12,800,037 13,047,607
ALPHA METALLURGICAL RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Amounts in thousands, except share and per share data) March 31, 2026 December 31, 2025 Assets Current assets: Cash and cash equivalents $ 317,231 $ 365,974 Short-term investments 49,646 49,582 Trade accounts receivable, net of allowance for credit losses of $2,858 and $2,519
as of March 31, 2026 and December 31, 2025, respectively 302,136 278,620 Inventories, net 213,102 193,000 Prepaid expenses and other current assets 27,360 31,132 Total current assets 909,475 918,308 Property, plant, and equipment, net of accumulated depreciation and amortization
of $805,966 and $774,101 as of March 31, 2026 and December 31, 2025, respectively 625,145 621,866 Owned and leased mineral rights, net of accumulated depletion and amortization of
$157,070 and $150,616 as of March 31, 2026 and December 31, 2025, respectively 410,489 416,944 Other acquired intangibles, net of accumulated amortization of $43,948 and $43,072
as of March 31, 2026 and December 31, 2025, respectively 33,576 34,452 Long-term restricted cash 127,217 126,911 Long-term restricted investments 34,399 34,356 Deferred income taxes 8,210 8,087 Other non-current assets 133,926 119,702 Total assets $ 2,282,437 $ 2,280,626 Liabilities and Stockholders' Equity Current liabilities: Current portion of long-term debt $ 3,231 $ 3,575 Trade accounts payable 92,984 66,169 Accrued expenses and other current liabilities 151,772 135,778 Total current liabilities 247,987 205,522 Long-term debt 8,977 9,841 Workers' compensation and black lung obligations 189,527 190,965 Pension obligations 83,281 87,317 Asset retirement obligations 203,632 204,745 Deferred income taxes 10,711 15,433 Other non-current liabilities 21,367 21,308 Total liabilities 765,482 735,131 Commitments and Contingencies Stockholders' Equity Preferred stock - par value $0.01, 5,000,000 shares authorized, none issued — — Common stock - par value $0.01, 50,000,000 shares authorized, 22,494,813 issued
and 12,752,824 outstanding at March 31, 2026 and 22,437,379 issued and
12,805,909 outstanding at December 31, 2025 225 224 Additional paid-in capital 855,765 852,030 Accumulated other comprehensive loss (58,698) (60,433) Treasury stock, at cost: 9,741,989 shares at March 31, 2026 and 9,631,470 shares
at December 31, 2025 (1,364,022) (1,341,027) Retained earnings 2,083,685 2,094,701 Total stockholders' equity 1,516,955 1,545,495 Total liabilities and stockholders' equity $ 2,282,437 $ 2,280,626
ALPHA METALLURGICAL RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (Amounts in thousands) Three Months Ended March 31, 2026 2025 Operating activities: Net loss $ (11,032) $ (33,947) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 39,926 43,910 Amortization of acquired intangibles 876 1,357 Gain on disposal of assets, net (2,053) (37) Accretion on asset retirement obligations 5,215 5,614 Employee benefit plans, net 6,266 5,618 Deferred tax benefit (5,329) (11,416) Stock-based compensation 3,736 3,437 Equity loss in affiliates 5,733 4,960 Other, net 2,476 135 Changes in operating assets and liabilities (16,768) 2,550 Net cash provided by operating activities 29,046 22,181 Investing activities: Capital expenditures (40,668) (38,450) Capital contributions to equity affiliates (13,403) (9,836) Purchases of investment securities (27,826) (14,663) Sales and maturities of investment securities 28,240 15,080 Other, net 62 94 Net cash used in investing activities (53,595) (47,775) Financing activities: Principal repayments of long-term debt (915) (822) Common stock repurchases and related expenses (22,901) (5,155) Other, net (72) (415) Net cash used in financing activities (23,888) (6,392) Net decrease in cash and cash equivalents and restricted cash (48,437) (31,986) Cash and cash equivalents and restricted cash at beginning of period 492,885 604,161 Cash and cash equivalents and restricted cash at end of period $ 444,448 $ 572,175 Supplemental disclosure of noncash investing and financing activities: Accrued capital expenditures $ 11,089 $ 10,785
The following table provides a reconciliation of cash and cash equivalents and restricted cash reported within the Condensed Consolidated Balance Sheets that sum to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows.
As of March 31, 2026 2025 Cash and cash equivalents $ 317,231 $ 447,990 Long-term restricted cash 127,217 124,185 Total cash and cash equivalents and restricted cash shown in the
Condensed Consolidated Statements of Cash Flows $ 444,448 $ 572,175
ALPHA METALLURGICAL RESOURCES, INC. AND SUBSIDIARIES ADJUSTED EBITDA RECONCILIATION (Amounts in thousands) Three Months Ended March 31, 2026 December 31, 2025 March 31, 2025 Net loss $ (11,032) $ (17,271) $ (33,947) Interest expense 841 730 763 Interest income (4,206) (3,273) (4,046) Income tax benefit (5,326) (9,757) (11,437) Depreciation, depletion and amortization 39,926 41,893 43,910 Non-cash stock compensation expense 3,736 3,193 3,437 Accretion on asset retirement obligations 5,215 5,501 5,614 Amortization of acquired intangibles 876 1,356 1,357 Non-recurring mine flood costs (1) — 6,098 — Adjusted EBITDA $ 30,030 $ 28,470 $ 5,651
(1) Non-recurring mine recovery and idle costs due to the water inundation at the Rolling Thunder mine in November 2025.
ALPHA METALLURGICAL RESOURCES, INC. AND SUBSIDIARIES RESULTS OF OPERATIONS Three Months Ended (In thousands, except for per ton data) March 31, 2026 December 31, 2025 March 31, 2025 Coal revenues $ 523,533 $ 519,060 $ 529,667 Less: freight and handling fulfillment revenues (76,214) (82,730) (83,924) Non-GAAP coal revenues $ 447,319 $ 436,330 $ 445,743 Non-GAAP coal sales realization per ton $ 124.39 $ 115.31 $ 118.61 Cost of coal sales (exclusive of items shown separately below) $ 474,389 $ 478,519 $ 504,584 Depreciation, depletion and amortization - production (1) 39,606 41,571 43,592 Accretion on asset retirement obligations 5,215 5,501 5,614 Amortization of acquired intangibles 876 1,356 1,357 Total cost of coal sales 520,086 526,947 555,147 Less: freight and handling costs (76,214) (82,730) (83,924) Less: depreciation, depletion and amortization - production (1) (39,606) (41,571) (43,592) Less: accretion on asset retirement obligations (5,215) (5,501) (5,614) Less: amortization of acquired intangibles (876) (1,356) (1,357) Less: idled and closed mine costs (9,872) (11,960) (5,991) Non-GAAP cost of coal sales $ 388,303 $ 383,829 $ 414,669 Non-GAAP cost of coal sales per ton $ 107.98 $ 101.43 $ 110.34 GAAP coal margin $ 3,447 $ (7,887) $ (25,480) GAAP coal margin per ton $ 0.96 $ (2.08) $ (6.78) Non-GAAP coal margin $ 59,016 $ 52,501 $ 31,074 Non-GAAP coal margin per ton $ 16.41 $ 13.87 $ 8.27 Tons sold 3,596 3,784 3,758
(1) Depreciation, depletion and amortization - production excludes the depreciation, depletion and amortization related to selling, general and administrative functions.
Three Months Ended March 31, 2026 (In thousands, except for per ton data) Tons Sold Coal Revenues Non-GAAP
Coal sales
realization per
ton % of Met Tons
Sold Domestic 809 $ 111,053 $ 137.27 24 % Export - Australian indexed 1,120 162,348 $ 144.95 33 % Export - other pricing mechanisms 1,423 156,981 $ 110.32 43 % Total Met segment - met coal 3,352 430,382 $ 128.40 100 % Met segment - thermal coal 244 16,937 $ 69.41 Non-GAAP coal revenues 3,596 447,319 $ 124.39 Add: freight and handling fulfillment revenues — 76,214 Coal revenues 3,596 $ 523,533
INVESTOR & MEDIA CONTACT: EMILY O'QUINN
InvestorRelations@AlphaMetResources.com
CorporateCommunications@AlphaMetResources.com
(423) 573-0369Cision
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- Top 3 Undervalued Small Caps With Insider Action In Global May 2026
May 8, 2026
In the midst of geopolitical tensions and fluctuating energy prices, global markets have experienced a mixed performance with large-cap stocks outpacing their small-cap counterparts. Despite these challenges, the Russell 2000 Index has shown resilience with a year-to-date increase of over 13%, highlighting potential opportunities within the small-cap sector. In this environment, identifying promising small-cap stocks often involves looking for companies that demonstrate strong fundamentals and strategic insider actions, which can signal confidence in future growth prospects amidst market volatility.
Top 10 Undervalued Small Caps With Insider Buying Globally
Name PE PS Discount to Fair Value Value Rating CellaVision 21.4x 3.9x 42.83% ★★★★★★ Security Bank 4.2x 0.9x 32.64% ★★★★★★ Nederman Holding 16.2x 0.8x 33.55% ★★★★★☆ Chorus Aviation 7.5x 0.4x 43.38% ★★★★★☆ Shoucheng Holdings 44.9x 9.7x 44.43% ★★★☆☆☆ Centurion 12.2x 4.2x -7.60% ★★★☆☆☆ ABL Group NA 0.4x -37.91% ★★★☆☆☆ PSC 11.7x 0.5x 47.26% ★★★☆☆☆ AB Dynamics NA 2.2x 35.80% ★★★☆☆☆ CapitaLand China Trust NA 3.9x -2.08% ★★★☆☆☆
Click here to see the full list of 166 stocks from our Undervalued Global Small Caps With Insider Buying screener.
We'll examine a selection from our screener results.
SiteMinder
Simply Wall St Value Rating: ★★★☆☆☆
Overview: SiteMinder is a company specializing in software and programming solutions for the hospitality industry, with a market capitalization of A$1.12 billion.
Operations: SiteMinder generates revenue primarily from its software and programming segment, reporting A$251.02 million in the latest period. The company has experienced fluctuations in its gross profit margin, reaching 25.67% recently. Operating expenses are a significant part of the cost structure, with notable allocations to research and development as well as sales and marketing efforts. Despite increasing revenue over time, SiteMinder continues to report net losses, with the latest net income margin at -6.13%.
PE: -57.1x
SiteMinder, a smaller company in the tech sector, shows potential despite its reliance on external borrowing for funding. Recent earnings for the half-year ending December 2025 reveal sales of A$131.1 million, up from A$104.45 million the previous year, with net losses narrowing to A$4.78 million from A$8.98 million a year earlier. Insider confidence is evident with recent share purchases by executives in early 2026, indicating faith in future growth prospects as earnings are forecasted to grow annually by over 60%.
Dive into the specifics of SiteMinder here with our thorough valuation report. Examine SiteMinder's past performance report to understand how it has performed in the past.
Story Continues
ASX:SDR Share price vs Value as at May 2026
Precinct Properties NZ & Precinct Properties Investments
Simply Wall St Value Rating: ★★★★☆☆
Overview: Precinct Properties NZ & Precinct Properties Investments is a New Zealand-based company specializing in flexible space, hotel and hospitality, investment management, and investment properties with a market cap of NZ$1.56 billion.
Operations: The company's primary revenue stream is derived from its investment properties, generating NZ$215.10 million, with additional contributions from hotel and hospitality (NZ$24.20 million), flexible space (NZ$20.50 million), and investment management (NZ$7.30 million). Over recent periods, the gross profit margin has shown a declining trend from 71.63% to 59.65%. Operating expenses have increased over time, impacting overall profitability alongside significant non-operating expenses in recent quarters.
PE: 410.0x
Precinct Properties Group, known for its strategic real estate investments, recently appointed Deloitte as its new auditor starting in 2028, reflecting strong governance practices. Despite facing a dip in net income to NZ$2.9 million for the half-year ending December 2025, insider confidence remains evident through share purchases over the past year. The company continues to navigate financial challenges with external borrowing as its primary funding source while maintaining a focus on future growth prospects projected at 25.92% annually.
Delve into the full analysis valuation report here for a deeper understanding of Precinct Properties NZ & Precinct Properties Investments. Explore historical data to track Precinct Properties NZ & Precinct Properties Investments' performance over time in our Past section.NZSE:PCT Share price vs Value as at May 2026
Property For Industry
Simply Wall St Value Rating: ★★★☆☆☆
Overview: Property For Industry is a company focused on property investment and management, with operations that include owning and managing a portfolio of industrial properties, and it has a market cap of NZ$1.62 billion.
Operations: The company primarily generates revenue from property investment and management, with recent figures showing a revenue of NZ$139.81 million. The cost of goods sold (COGS) is reported at NZ$22.806 million, contributing to a gross profit margin of 83.69%. Operating expenses are recorded at NZ$11.495 million, while non-operating expenses stand at -NZ$18.693 million, impacting the net income outcome significantly in recent periods.
PE: 9.5x
Property For Industry, a small company in the real estate sector, has shown promising financial performance with sales reaching NZ$73.58 million for the half year ending December 2025. Net income rose to NZ$46.94 million from NZ$28.76 million the previous year, indicating strong growth potential. Insider confidence is evident as an independent director purchased 77,420 shares recently valued at approximately NZ$170,319. The company's revised dividend guidance signals positive trading conditions and potential future growth despite reliance on external borrowing for funding.
Unlock comprehensive insights into our analysis of Property For Industry stock in this valuation report. Understand Property For Industry's track record by examining our Past report.NZSE:PFI Ownership Breakdown as at May 2026
Turning Ideas Into Actions
Take a closer look at our Undervalued Global Small Caps With Insider Buying list of 166 companies by clicking here. Already own these companies? Link your portfolio to Simply Wall St and get alerts on any new warning signs to your stocks. Simply Wall St is your key to unlocking global market trends, a free user-friendly app for forward-thinking investors.
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This article by Simply Wall St is general in nature. We provide commentary based on historical data and analyst forecasts only using an unbiased methodology and our articles are not intended to be financial advice. It does not constitute a recommendation to buy or sell any stock, and does not take account of your objectives, or your financial situation. We aim to bring you long-term focused analysis driven by fundamental data. Note that our analysis may not factor in the latest price-sensitive company announcements or qualitative material. Simply Wall St has no position in any stocks mentioned.
Companies discussed in this article include ASX:SDR NZSE:PCT and NZSE:PFI.
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